[Federal Register Volume 87, Number 66 (Wednesday, April 6, 2022)]
[Proposed Rules]
[Pages 20036-20216]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-04551]



[[Page 20035]]

Vol. 87

Wednesday,

No. 66

April 6, 2022

Part II





Environmental Protection Agency





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40 CFR Parts 52, 75, 78, et al.





Federal Implementation Plan Addressing Regional Ozone Transport for the 
2015 Ozone National Ambient Air Quality Standard; Proposed Rule

  Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / 
Proposed Rules  

[[Page 20036]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 52, 75, 78 and 97

[EPA-HQ-OAR-2021-0668; FRL 8670-01-OAR]
RIN 2060-AV51


Federal Implementation Plan Addressing Regional Ozone Transport 
for the 2015 Ozone National Ambient Air Quality Standard

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This action proposes Federal Implementation Plan (FIP) 
requirements to address twenty-six states' obligations to eliminate 
significant contribution to nonattainment, or interference with 
maintenance, of the 2015 ozone National Ambient Air Quality Standard 
(NAAQS) in other states. The U.S. Environmental Protection Agency (EPA) 
is proposing this action under the ``good neighbor'' or ``interstate 
transport'' provision of the Clean Air Act (CAA or Act). The Agency 
proposes establishing nitrogen oxides emissions budgets requiring 
fossil fuel-fired power plants in 25 states to participate in an 
allowance-based ozone season trading program beginning in 2023. The 
Agency is also proposing to establish nitrogen oxides emissions 
limitations applicable to certain other industrial stationary sources 
in 23 states with an earliest possible compliance date of 2026. These 
industrial source types are: Reciprocating internal combustion engines 
in Pipeline Transportation of Natural Gas; kilns in Cement and Cement 
Product Manufacturing; boilers and furnaces in Iron and Steel Mills and 
Ferroalloy Manufacturing; furnaces in Glass and Glass Product 
Manufacturing; and high-emitting equipment and large boilers in Basic 
Chemical Manufacturing, Petroleum and Coal Products Manufacturing, and 
Pulp, Paper, and Paperboard Mills.

DATES: Comments must be received on or before June 6, 2022.
    Public Hearing: The EPA will hold a virtual public hearing on April 
21, 2022. Please refer to the SUPPLEMENTARY INFORMATION section for 
additional information on the public hearing.
    Information Collection Request (ICR): Under the Paperwork Reduction 
Act (PRA), comments on the information collection provisions are best 
assured of consideration if the Office of Management and Budget (OMB) 
receives a copy of your comments on or before May 6, 2022.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2021-0668; via the Federal eRulemaking Portal: https://www.regulations.gov/ (our preferred method). Follow the online 
instructions for submitting comments.
    Instructions: All submissions received must include the Docket ID 
No. for this rulemaking. Comments received may be posted without change 
to https://www.regulations.gov/, including any personal information 
provided. For detailed instructions on sending comments and additional 
information on the rulemaking process, see the ``Public Participation'' 
heading of the SUPPLEMENTARY INFORMATION section of this document. Out 
of an abundance of caution for members of the public and our staff, the 
EPA Docket Center and Reading Room are open to the public by 
appointment only to reduce the risk of transmitting COVID-19. Our 
Docket Center staff also continues to provide remote customer service 
via email, phone, and webform. Hand deliveries and couriers may be 
received by scheduled appointment only. For further information on EPA 
Docket Center services and the current status, please visit us online 
at https://www.epa.gov/dockets.
    The virtual public hearing will be held on April 21, 2022. The 
virtual public hearing will convene at 10 a.m. Eastern Time (ET) and 
will conclude at 7 p.m. ET. The EPA may close a session 15 minutes 
after the last pre-registered speaker has testified if there are no 
additional speakers. For information or questions about the public 
hearing, please contact Ms. Holly DeJong at [email protected]. The 
EPA will announce further details at https://www.epa.gov/csapr/csapr-2015-ozone-naaqs. Refer to the SUPPLEMENTARY INFORMATION section for 
additional information.

FOR FURTHER INFORMATION CONTACT: Ms. Elizabeth Selbst, Air Quality 
Policy Division, Office of Air Quality Planning and Standards (C539-
01), Environmental Protection Agency, 109 TW Alexander Drive, Research 
Triangle Park, NC 27711; telephone number: (919)-541-3918; email 
address: [email protected].

SUPPLEMENTARY INFORMATION:

Preamble Glossary of Terms and Abbreviations

    The following are abbreviations of terms used in the preamble.

2016v1 2016 Version 1 Emissions Modeling Platform
2016v2 2016 Version 2 Emissions Modeling Platform
4-Step Framework 4-Step Interstate Transport Framework
ACS American Community Survey
AEO Annual Energy Outlook
AQAT Air Quality Assessment Tool
AQMTSD Air Quality Modeling Technical Support Document
BACT Best Available Control Technology
BPT Benefit Per Ton
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CBI Confidential Business Information
CCR Coal Combustion Residual
CDC Centers for Disease Control and Prevention
CEMS Continuous Emissions Monitoring Systems
CES Clean Energy Standards
CHP Combined Heat and Power
CMDB Control Measures Database
CMV Commercial Marine Vehicle
CoST Control Strategy Tool
CPT Cost Per Ton
CSAPR Cross-State Air Pollution Rule
EGU Electric Generating Unit
EIA U.S. Energy Information Agency
EISA Energy Independence and Security Act
ELG Effluent Limitation Guidelines
E.O. Executive Order
EPA or the Agency United States Environmental Protection Agency
FFS Finding of Failure To Submit
FIP Federal Implementation Plan
GIS Geographic Information System
HDGHG Greenhouse Gas Emissions and Fuel Efficiency Standards for 
Medium- and Heavy-Duty Engines and Vehicles
HEDD High Electricity Demand Days
ICI Industrial, Commercial, and Institutional
I/M Inspection and Maintenance
IPM Integrated Planning Model
LNB Low-NOX Burners
MJO Multi-Jurisdictional Organization
MOVES Motor Vehicle Emission Simulator
MSAT2 Mobile Source Air Toxics Rule
MWC Municipal Waste Combustor
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NEEDS National Electric Energy Data System
NEI National Emissions Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
No SISNOSE No Significant Economic Impact on a Substantial Number of 
Small Entities
Non-EGU Non-Electric Generating Unit
NOX Nitrogen Oxides
NSPS New Source Performance Standard
NREL National Renewable Energy Lab
NTTAA National Technology Transfer and Advancement Act
OFA Over-Fire Air
OMB United States Office of Management and Budget
OSAT/APCA Ozone Source Apportionment Technology/Anthropogenic 
Precursor Culpability Analysis
OTC Ozone Transport Commission
OTR Ozone Transport Region
OTSA Oklahoma Tribal Statistical Area
PEMS Predictive Emissions Monitoring Systems

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PM2.5 Fine Particulate Matter
ppb parts per billion
ppm parts per million
ppmvd parts per million by volume, dry
PRA Paperwork Reduction Act
RACT Reasonably Available Control Technology
RFA Regulatory Flexibility Act
RICE Reciprocating Internal Combustion Engines
ROP Rate of Progress
RPS Renewable Portfolio Standards
RRF Relative Response Factor
SAFE Safer Affordable Fuel-Efficient Vehicles Rule
SAFETEA Safe, Accountable, Flexible, Efficient, Transportation 
Equity Act
SCR Selective Catalytic Reduction
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel Emissions
SNCR Selective Non-Catalytic Reduction
SO2 Sulfur Dioxide
tpd ton per day
TSD Technical Support Document
UMRA Unfunded Mandates Reform Act
VMT Vehicle Miles Traveled
VOCs Volatile Organic Compounds
WRAP Western Regional Air Partnership
WRF Weather Research and Forecasting

Table of Contents

I. Executive Summary
    A. Purpose of Regulatory Action
    1. Emissions Limitations for EGUs Established by the Proposed 
Rule
    2. Emissions Limitations for Non-EGU Stationary Point Sources 
Established by the Proposed Rule
    3. Proposed Error Correction for Previously Approved 2015 Ozone 
Transport SIP
    4. Request for Comment on All Aspects of the Proposal
    B. Summary of the Major Provisions of the Regulatory Action
    C. Benefits and Costs
II. Public Participation
    A. Written Comments
    B. Submitting Confidential Business Information
    C. Participation in Virtual Public Hearing
III. General Information
    A. Does this action apply to me?
    B. What action is the Agency taking?
    C. What is the Agency's legal authority for taking this action?
    1. Statutory Authority
    D. What actions has EPA previously issued to address regional 
ozone transport?
IV. Air Quality Issues Addressed and Overall Approach for the 
Proposed Rule
    A. The Interstate Ozone Transport Air Quality Challenge
    1. Nature of Ozone and the Ozone NAAQS
    2. Ozone Transport
    3. Health and Environmental Effects
    B. Proposed Rule Approach
    1. The 4-Step Interstate Transport Framework
    a. Step 1 Approach
    b. Step 2 Approach
    c. Step 3 Approach
    d. Step 4 Approach
    2. FIP Authority for Each State Covered by the Proposed Rule
    C. Other CAA Authorities for This Action
    1. Correction of EPA's Determination Regarding Delaware's SIP 
Submission and Its Impact on EPA's FIP Authority for Delaware
    2. Application of Rule in Indian Country and Necessary or 
Appropriate Finding
    a. Indian Country Subject to State Implementation Planning 
Authority
V. Analyzing Downwind Air Quality Problems and Contributions From 
Upwind States
    A. Selection of Analytic Years for Evaluating Ozone Transport 
Contributions to Downwind Air Quality Problems
    B. Overview of Air Quality Modeling Platform
    C. Emissions Inventories
    1. Foundation Emissions Inventory Data Sets
    2. Development of Emissions Inventories for EGUs
    3. Development of Emissions Inventories for Non-EGU Point 
Sources
    4. Development of Emissions Inventories for Onroad Mobile 
Sources
    5. Development of Emissions Inventories for Commercial Marine 
Vessels
    6. Development of Emissions Inventories for Other Nonroad Mobile 
Sources
    7. Development of Emissions Inventories for Nonpoint Sources
    D. Air Quality Modeling To Identify Nonattainment and 
Maintenance Receptors
    E. Pollutant Transport From Upwind States
    1. Air Quality Modeling To Quantify Upwind State Contributions
    2. Application of Contribution Screening Threshold
    a. States That Contribute at or Above the Screening Threshold
    F. Treatment of Certain Receptors in California and Implications 
for Oregon's Good Neighbor Obligations for 2015 Ozone NAAQS
VI. Quantifying Upwind-State NOX Emissions Reduction 
Potential To Reduce Interstate Ozone Transport for the 2015 Ozone 
NAAQS
    A. The Multi-Factor Test for Determining Significant 
Contribution
    B. Identifying Control Stringency Levels
    1. EGU NOX Mitigation Strategies
    a. Optimizing Existing SCRs
    b. Installing State-of-the-Art NOX Combustion 
Controls
    c. Optimizing Already Operating SNCRs or Turning on Idled 
Existing SNCRs
    d. Installing New SNCRs
    e. Installing New SCRs
    f. Generation Shifting
    2. Non-EGU NOX Mitigation Strategies
    a. Determining Non-EGU NOX Reduction Potential
    3. Other Stationary Sources NOX Mitigation Strategies
    a. Units Less Than or Equal to 25 MW
    b. Municipal Solid Waste Units
    c. Cogeneration Units
    4. Mobile Source NOX Mitigation Strategies
    C. Control Stringencies Represented by Cost Threshold ($ per 
Ton) and Corresponding Emissions Reductions
    1. EGU Emissions Reduction Potential by Cost Threshold
    2. Non-EGU Emissions Reduction Potential--Cost Threshold Up to 
$7,500/Ton
    D. Assessing Cost, EGU and Non-EGU NOX Reductions, 
and Air Quality
    1. EGU Assessment
    2. Non-EGU Assessment
    a. Request for Comment on Non-EGU Control Strategies and 
Measures
    3. Combined EGU and Non-EGU Assessment
    4. Over-Control Analysis
VII. Implementation of Emissions Reductions
    A. NOX Reduction Implementation Schedule
    1. 2023-2025: EGU NOX Reductions Beginning in 2023
    2. 2026 and Later Years: EGU and Non-EGU EGU NOX 
Reductions Beginning in 2026
    a. EGU Schedule for 2026 and Later Years
    b. Non-EGU Schedule for 2026 and Later Years
    B. Regulatory Requirements for EGUs
    1. Trading Program Background and Overview of Proposed Revisions
    a. Current CSAPR Trading Program Design Elements and Identified 
Concerns
    b. Enhancements To Maintain Selected Control Stringency Over 
Time
    i. Revised Emissions Budget-Setting Process
    ii. Allowance Bank Recalibration
    c. Enhancements To Improve Emissions Performance at Individual 
Units
    i. Unit-Specific Backstop Daily Emissions Rates
    ii. Unit-Specific Emissions Limitations Contingent on Assurance 
Level Exceedances
    2. Expansion of Geographic Scope
    3. Applicability and Tentative Identification of Newly Affected 
Units
    4. New and Revised State Emissions Budgets
    a. Methodology for Determining Preset State Emissions Budgets 
for the 2023 and 2024 Control Periods
    b. Methodology for Determining Dynamic State Emissions Budgets 
for Control Periods in 2025 and Beyond
    c. Proposed and Illustrative State Emissions Budgets
    5. Variability Limits and Assurance Levels
    6. Annual Recalibration of Allowance Bank
    7. Unit-Specific Backstop Daily Emissions Rates
    8. Unit-Specific Emissions Limitations Contingent on Assurance 
Level Exceedances
    9. Unit-Level Allowance Allocation and Recordation Procedures
    a. Set-Asides of Portions of State Emissions Budgets for New 
Units
    b. Allocations to Existing Units, Including Units That Cease 
Operation
    c. Allocations From Portions of State Emissions Budgets Set 
Aside for New Units
    d. Incorrectly Allocated Allowances
    10. Other Trading Program Provisions
    a. Designated Representative Requirements
    b. Monitoring and Reporting Requirements
    11. Transitional Provisions
    a. Prorating Emissions Budgets, Assurance Levels, and Unit-Level 
Allowance

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Allocations in the Event of an Effective Date After May 1, 2023
    b. Creation of Additional Group 3 Allowance Bank for 2023 
Control Period
    c. Recall of Group 2 Allowances for Control Periods After 2022
    12. Conforming Revisions to Other Regulations
    C. Regulatory Requirements for Non-EGUs
    1. Pipeline Transportation of Natural Gas
    2. Cement and Concrete Product Manufacturing
    3. Iron and Steel Mills and Ferroalloy Manufacturing
    4. Glass and Glass Product Manufacturing
    5. Boilers From Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, and Pulp, Paper, and Paperboard Mills
    a. Coal-Fired Industrial Boilers
    b. Oil-Fired Industrial Boilers
    c. Gas-Fired Industrial Boilers
    D. Submitting a SIP
    1. SIP Option To Modify Allocations for 2024 Under EGU Trading 
Program
    2. SIP Option To Modify Allocations for 2025 and Beyond Under 
EGU Trading Program
    3. SIP Option To Replace the Federal EGU Trading Program With an 
Integrated State EGU Trading Program
    4. SIP Revisions That Do Not Use the New Trading Program
    5. SIP Revision Requirements for Non-EGU Emissions Limits
    E. Title V Permitting
    F. Relationship to Other Emissions Trading and Ozone Transport 
Programs
    1. NOX SIP Call
    2. Acid Rain Program
    3. Other Current Emissions Trading Programs
VIII. Environmental Justice Considerations, Implications, and 
Stakeholder Outreach
    A. Introduction
    B. Analytical Considerations
    C. Outreach and Engagement
IX. Costs, Benefits, and Other Impacts of the Proposed Rule
X. Summary of Proposed Changes to the Regulatory Text for the 
Federal Implementation Plans and Trading Programs for EGUs
    A. Amendments to FIP Provisions in 40 CFR Part 52
    B. Amendments to Group 3 Trading Program and Related Regulations
    C. Transitional Provisions
    D. Clarifications and Conforming Revisions
XI. 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. Determinations Under CAA Section 307(b)(1) and (d)

I. Executive Summary

    This proposed rule would resolve the interstate transport 
obligations of 26 states under CAA section 110(a)(2)(D)(i)(I), referred 
to as the ``good neighbor provision'' or the ``interstate transport 
provision'' of the Act, for the 2015 ozone NAAQS. On October 1, 2015, 
the EPA revised the primary and secondary 8-hour standards for ozone to 
70 parts per billion (ppb).\1\ States were required to provide ozone 
infrastructure State Implementation Plan (SIP) submissions to fulfill 
interstate transport obligations for the 2015 ozone NAAQS by October 1, 
2018.
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    \1\ See 80 FR 65291 (October 26, 2015).
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    The EPA proposes to make a finding that interstate transport of 
ozone precursor emissions from 26 upwind states (Alabama, Arkansas, 
California, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New 
York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, 
West Virginia, Wisconsin, and Wyoming) is significantly contributing to 
downwind nonattainment or interfering with maintenance of the 2015 
ozone NAAQS in other states, based on projected nitrogen oxides 
(NOX) emissions in the 2023 ozone season. The EPA is 
proposing to issue FIP requirements to eliminate interstate transport 
of ozone precursors from these 26 states that significantly contributes 
to nonattainment or interferes with maintenance of the NAAQS in other 
states.
    The EPA is proposing FIPs for 23 states for which the Agency has 
not approved an ozone transport SIP that was submitted for the 2015 
ozone NAAQS: Alabama, Arkansas, California, Illinois, Indiana, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Tennessee, 
Texas, Utah, West Virginia, Wisconsin, and Wyoming. In this proposed 
rule, the EPA is proposing to issue FIPs for two states--Pennsylvania 
and Virginia--for which the EPA issued a Finding of Failure to Submit 
for 2015 ozone transport SIPs with an effective date of January 6, 
2020. Under CAA section 301(d)(4), the EPA proposes to extend FIP 
requirements to apply in Indian country located within the upwind 
geography of the proposed rule, including Indian reservation lands and 
other areas of Indian country over which the EPA or a tribe has 
demonstrated that a tribe has jurisdiction.\2\ The EPA is also 
proposing a FIP for Delaware and an error correction for the Agency's 
May 1, 2020, approval at 85 FR 25307 of the interstate transport 
elements for Delaware's October 11, 2018, and December 26, 2019, ozone 
infrastructure SIP submissions.
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    \2\ In general, specific tribal names or reservations are not 
identified separately in this proposal except as needed. See Section 
IV.C.2 of this notice for further discussion.
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    In this proposed rule, the EPA proposes to establish new ozone 
season NOX emissions budgets beginning in 2023 for Electric 
Generating Unit (EGU) sources. The EPA is also proposing to establish 
emissions limitations beginning in 2026 for certain other industrial 
stationary sources (referred to generally as ``non-Electric Generating 
Units'' (non-EGUs)). Taken together, these strategies will fully 
eliminate the covered states' significant contribution to downwind 
ozone air quality problems in other states.
    The EPA proposes to implement the necessary emissions reductions as 
follows. The proposed FIP requirements establish ozone season 
NOX emissions budgets for EGUs in 25 states (Alabama, 
Arkansas, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New 
York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, 
West Virginia, Wisconsin, and Wyoming) and require EGUs in these states 
to participate in a revised version of the Cross-State Air Pollution 
Rule (CSAPR) NOX Ozone Season Group 3 Trading Program that 
was previously established in the Revised CSAPR Update.\3\ The EPA 
proposes to amend existing FIPs for 12 states currently participating 
in the CSAPR NOX Ozone Season Group 3 Trading Program 
(Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New 
Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia) to 
replace their existing emissions budgets established in the Revised 
CSAPR Update (with respect to the 2008 ozone NAAQS) with new

[[Page 20039]]

emissions budgets. For eight states currently covered by the CSAPR 
NOX Ozone Season Group 2 Trading Program under SIPs or FIPs, 
the EPA is proposing to issue new FIPs for two states (Alabama and 
Missouri) and amend existing FIPs for six states (Arkansas, 
Mississippi, Oklahoma, Tennessee, Texas, and Wisconsin) to transition 
EGU sources in these states from the Group 2 program to the revised 
Group 3 trading program, beginning with the 2023 ozone season. EPA 
proposes to issue new FIPs for five states not currently covered by any 
CSAPR NOX ozone season trading program: Delaware, Minnesota, 
Nevada, Utah, and Wyoming.
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    \3\ As explained in Section VI.C.1 of this notice, EPA proposes 
finding that EGU sources within the State of California are 
sufficiently controlled such that no further emissions reductions 
are needed from them to eliminate significant contribution to 
downwind states.
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    Under this proposed rulemaking, emissions reductions in the 
selected control stringency would be achieved as soon as they are 
available, some of which are scheduled to occur by the 2023 ozone 
season and prior to the August 3, 2024, attainment date for areas 
classified as Moderate nonattainment for the 2015 ozone NAAQS, and the 
rest of which occur as soon as possible thereafter through the 2026 
ozone season, prior to the August 3, 2027, attainment date for areas 
classified as Serious nonattainment for the 2015 ozone NAAQS. As 
discussed in Section VII.A.2 of this notice, the EPA proposes to find 
that the 2026 ozone season is as expeditious as practicable to 
implement substantial emissions reductions from potential new post-
combustion control installations at EGUs as well as from installation 
of new pollution controls at non-EGUs.
    These EGU emissions reductions are scheduled to begin in the 2026 
ozone season based on the feasibility of control installation for EGUs 
in 22 states that remain linked to downwind nonattainment and 
maintenance receptors in that year. These 22 states are: Arkansas, 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, West Virginia, Wisconsin, and 
Wyoming. The additional emissions reductions required for these states 
are based primarily on the potential retrofit of additional post-
combustion controls for NOX on most coal steam EGUs and a 
portion of oil/gas steam EGUs that are currently lacking such controls.
    In this proposed rule, the EPA introduces additional features to 
the allowance-based trading program approach for EGUs, including 
dynamic adjustments of the emissions budgets over time and backstop 
daily emissions rate limits for most coal-fired units, that will help 
maintain control stringency over time and improve emissions performance 
at individual units, providing further assurance that existing 
pollution controls will be operated during the ozone season and that 
the emission reductions necessary to meet good neighbor requirements 
will be achieved.
    The EPA proposes to find that NOX emissions from non-EGU 
sources are significantly contributing to nonattainment or interfering 
with maintenance of the 2015 ozone NAAQS and that cost-effective 
controls for NOX emissions reductions are available in 
certain industrial source categories that would result in meaningful 
air quality improvements in downwind receptors. The EPA proposes to 
require emissions limitations beginning in 2026 for non-EGUs located 
within 23 states: Arkansas, California, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, 
Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, 
Utah, Virginia, West Virginia, Wisconsin, and Wyoming. The proposed 
rule establishes NOX emissions limitations during the ozone 
season for the following unit types for sources in non-EGU industries: 
Reciprocating internal combustion in Pipeline Transportation of Natural 
Gas sources; kilns in Cement and Cement Product Manufacturing sources; 
boilers and furnaces in Iron and Steel Mills and Ferroalloy 
Manufacturing sources; furnaces in Glass and Glass Product 
Manufacturing sources; and high-emitting equipment and large boilers in 
Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills.

A. Purpose of the Regulatory Action

    The purpose of this rulemaking is to protect public health and the 
environment by reducing interstate transport of certain air pollutants 
that significantly contribute to nonattainment, or interfere with 
maintenance, of the 2015 ozone NAAQS in other states. Ground-level 
ozone has detrimental effects on human health as well as vegetation and 
ecosystems. Acute and chronic exposure to ozone in humans is associated 
with premature mortality and a number of morbidity effects, such as 
asthma exacerbation. Ozone exposure can also negatively impact 
ecosystems by limiting tree growth, causing foliar injury, and changing 
ecosystem community composition. Section IV of this proposed rule 
provides additional evidence of the harmful effects of ozone exposure 
on human health and the environment. Studies have established that 
ozone air pollution can be transported over hundreds of miles, with 
elevated ground-level ozone concentrations occurring in rural and 
metropolitan areas.4 5 Assessments of ozone control 
approaches have concluded that control strategies targeting reduction 
of NOX emissions are an effective method to reduce regional-
scale ozone transport.\6\
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    \4\ Bergin, M.S. et al. (2007) Regional air quality: Local and 
interstate impacts of NOX and SO2 emissions on 
ozone and fine particulate matter in the eastern United States. 
Environmental Sci & Tech. 41: 4677-4689.
    \5\ Liao, K. et al. (2013) Impacts of interstate transport of 
pollutants on high ozone events over the Mid-Atlantic United States. 
Atmospheric Environment 84, 100-112.
    \6\ See 82 FR 51238, 51248 (November 3, 2017) [citing 76 FR 
48208, 48222 (August 8, 2011)] and 63 FR 57381 (October 27, 1998).
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    CAA section 110(a)(2)(D)(i)(I) requires states to prohibit 
emissions that will contribute significantly to nonattainment or 
interfere with maintenance in any other state with respect to any 
primary or secondary NAAQS.\7\ States fulfill their primary 
responsibility to address interstate transport emissions under the good 
neighbor provision by submitting SIPs containing enforceable emission 
limitations and other control measures, means, or techniques required 
to address the interstate transport provision. Within 3 years of the 
EPA promulgating a new or revised NAAQS, states are required to provide 
infrastructure SIP submittals, including good neighbor SIPs. See CAA 
section 110(a)(1) and (2). When states do not submit approvable 
interstate transport SIPs or fail to submit interstate transport SIPs 
by the statutory deadline, the CAA requires the EPA to issue FIPs to 
ensure that states eliminate their significant contribution to downwind 
air quality problems under the good neighbor provision. See generally 
CAA section 110(k) and 110(c). As such, in this proposed rule, the EPA 
is proposing requirements to fully address good neighbor obligations 
for these states for the 2015 ozone NAAQS under its authority to 
promulgate FIPs under CAA section 110(c).
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    \7\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
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    It is appropriate to issue this proposal at this time for at least 
three reasons. First, this proposal will ensure that necessary 
emissions reductions to eliminate significant contribution are achieved 
as expeditiously as practicable. The EPA's anticipated timing will 
provide for all possible emissions reductions to go into effect

[[Page 20040]]

beginning in the 2023 ozone season, which is aligned with the next 
upcoming attainment date of August 3, 2024, for areas classified as 
Moderate nonattainment under the 2015 ozone standard. Additional 
emissions reductions that the EPA finds not possible to implement by 
that attainment date are proposed to take effect as expeditiously as 
practicable, with the full suite of emissions reductions taking effect 
by the 2026 ozone season, which is aligned with the August 3, 2027, 
attainment date for areas classified as Serious nonattainment under the 
2015 ozone NAAQS. As explained in sections V.A, VI, and VII.A of this 
proposed rule, these proposed timeframes for eliminating significant 
contribution are consistent with the provisions of title I of the CAA. 
Second, this proposal will provide states with as much information as 
the EPA can supply at this time to support their ability to submit SIP 
revisions to achieve the emissions reductions the EPA believes 
necessary to eliminate significant contribution. Third, for all of the 
states included in this proposed rule, the EPA's modeling and analysis 
indicate that additional emissions reductions beyond those which are 
provided in any state's 2015 ozone transport SIP are necessary to 
eliminate significant contribution.
    The EPA anticipates that the states covered in this proposed FIP 
rulemaking may not have adequate provisions in their SIPs to address 
their interstate transport obligations for the 2015 ozone NAAQS. As 
discussed in Section IV.B.2 of this proposed rule, the EPA has, for 
certain states, made findings that the state failed to submit a 
complete good neighbor SIP revision for the 2015 ozone NAAQS. For 
certain other states, the EPA has proposed, but has not finalized, 
actions disapproving good neighbor SIP revisions. And for other states, 
the EPA has not yet proposed action on their good neighbor SIP 
submittals, but these submittals are currently under review, and EPA 
intends to act on these submittals in the coming months. The EPA will 
not finalize this proposed FIP action for any state for which it has 
not taken final action either disapproving that state's good neighbor 
SIP submittal or finding that the state failed to submit a complete 
SIP.
    The EPA conducted air quality modeling for future analytic years to 
identify (1) the downwind areas that are expected to have trouble 
attaining or maintaining the 2015 ozone NAAQS in the future and (2) the 
contribution of ozone transport from upwind states to the downwind air 
quality problems. Section V of this proposed rule provides a full 
description of the results of EPA's air quality modeling and relevant 
analyses for the proposed rulemaking. Based on EPA's air quality 
analysis, a total of 27 upwind states are linked above the 1 percent of 
the NAAQS threshold to downwind air quality problems in other states. 
The EPA had previously approved 2015 ozone transport SIPs submitted by 
two of these states--Oregon and Delaware--and proposes in this proposed 
rule to issue an error correction for its prior approval of Delaware's 
2015 ozone transport SIP (see Section IV.C.1 of this notice for 
additional information on the proposed error correction). The EPA is 
not proposing any change to its prior approval of Oregon's 2015 ozone 
transport SIP, a determination which is further described in Section 
V.F of this proposed rule.
    In this proposed rule, the EPA is proposing to issue FIP 
requirements for 26 states, which include emissions reductions for EGU 
sources within the borders of 25 states (described in Section VII.B of 
this proposed rule) and include emissions reductions for non-EGU 
sources within the borders of 23 states (described in Section VII.C in 
this proposed rule). Based on EPA's assessment of remaining air quality 
issues and additional emissions control strategies, the EPA further 
proposes to find that the EGU and non-EGU NOX emissions 
reductions required in the proposed rule would fully eliminate these 
states' significant contributions to downwind air quality problems for 
the 2015 ozone NAAQS. By eliminating significant contribution from 
these upwind states, this rule, if finalized as proposed, will make 
substantial and meaningful improvements in air quality by reducing 
ozone levels at the identified downwind receptors as well as many other 
areas of the country.
1. Emissions Limitations for EGUs Established by the Proposed Rule
    In this proposed rule, the EPA proposes to issue FIP requirements 
that include new NOX ozone season emissions budgets for EGU 
sources within the borders of the 25 states listed in Table I.A-1, with 
implementation of these emissions budgets beginning in the 2023 ozone 
season. The EPA proposes to find that these emissions reductions are 
necessary to address upwind states' interstate transport obligations 
for the 2015 ozone NAAQS.

    Table I.A-1--Proposed List of 25 Covered States for EGU Emissions
               Reductions for the 2015 8-Hour Ozone NAAQS
------------------------------------------------------------------------
                                  State
-------------------------------------------------------------------------
Alabama
Arkansas
Delaware
Illinois
Indiana
Kentucky
Louisiana
Maryland
Michigan
Minnesota
Mississippi
Missouri
Nevada
New Jersey
New York
Ohio
Oklahoma
Pennsylvania
Tennessee
Texas
Utah
Virginia
West Virginia
Wisconsin
Wyoming
------------------------------------------------------------------------

    The EPA proposes to expand the CSAPR NOX Ozone Season 
Group 3 Trading Program beginning in the 2023 ozone season. 
Specifically, the FIPs would require power plants within the borders of 
the 25 states listed in Table I.A-1 to participate in a revised version 
of the CSAPR NOX Ozone Season Group 3 Trading Program 
created by the Revised CSAPR Update. Affected EGUs within the borders 
of twelve states currently participating in the Group 3 Trading Program 
under FIPs or SIPs would remain in the program, with revised provisions 
beginning in the 2023 ozone season, under this proposed rule: Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, 
Ohio, Pennsylvania, Virginia, and West Virginia. The FIPs would also 
require affected EGUs within the borders of eight states currently 
covered by the CSAPR NOX Ozone Season Group 2 Trading 
Program (the ``Group 2 trading program'') under existing FIPs or 
existing SIPs to transition from the Group 2 program to the revised 
Group 3 trading program beginning with the 2023 control period: 
(Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Tennessee, Texas, 
and Wisconsin).\8\ Finally, the EPA is

[[Page 20041]]

proposing to issue new FIPs for EGUs within the borders of five states 
not currently covered by any CSAPR trading program for seasonal 
NOX emissions: Delaware, Minnesota, Nevada, Utah, and 
Wyoming. If the proposed FIP is finalized, sources in these states 
would enter the Group 3 trading program in the 2023 control period 
following the effective date of the final rule.\9\ In all cases, if the 
state submits and the EPA approves a SIP revision that would fully 
achieve the emissions reductions needed to meet the state's good 
neighbor obligations with respect to the 2015 ozone NAAQS before a 
final rule is promulgated in this rulemaking, the proposed FIP 
requirements summarized above would not be finalized. Refer to Section 
VII.B of this proposed rule for details on EGU regulatory requirements.
---------------------------------------------------------------------------

    \8\ Six of these eight states (Arkansas, Mississippi, Oklahoma, 
Tennessee, Texas, and Wisconsin) currently participate in the 
federal Group 2 trading program pursuant to the FIPs finalized in 
the CSAPR Update, so the FIPs proposed in this rulemaking would 
amend the existing FIPs for these states. The other two states 
(Alabama and Missouri) have already replaced the FIPs finalized in 
the CSAPR Update with approved SIP revisions that require their EGUs 
to participate in state Group 2 trading programs integrated with the 
federal Group 2 trading program, so the FIPs proposed in this action 
would constitute new FIPs for these states, and the EPA would cease 
implementation of the state Group 2 trading programs included in the 
two states' SIPs.
    \9\ Two states, Kansas and Iowa, will remain in the Group 2 
Trading Program.
---------------------------------------------------------------------------

2. Emissions Limitations for Non-EGU Stationary Point Sources 
Established by the Proposed Rule
    In this proposed rule, the EPA proposes to issue FIP requirements 
that include new NOX emissions limitations for non-Electric 
Generating Unit (non-EGU) sources in 23 states, with earliest possible 
compliance dates for these emissions limitations beginning in 2026. The 
EPA proposes to require emissions reductions from non-EGU sources to 
address interstate transport obligations for the 2015 ozone NAAQS for 
the 23 states listed in Table I.A-2.

  Table I.A-2--Proposed List of 23 Covered States for Non-EGU Emissions
               Reductions for the 2015 8-Hour Ozone NAAQS
------------------------------------------------------------------------
                                  State
-------------------------------------------------------------------------
Arkansas
California
Illinois
Indiana
Kentucky
Louisiana
Maryland
Michigan
Minnesota
Mississippi
Missouri
Nevada
New Jersey
New York
Ohio
Oklahoma
Pennsylvania
Texas
Utah
Virginia
West Virginia
Wisconsin
Wyoming
------------------------------------------------------------------------

    The EPA is proposing to require emissions limitations for the 
following unit types in non-EGU industries: Reciprocating internal 
combustion engines in Pipeline Transportation of Natural Gas sources; 
kilns in Cement and Cement Product Manufacturing sources; boilers and 
furnaces in Iron and Steel Mills and Ferroalloy Manufacturing sources; 
furnaces in Glass and Glass Product Manufacturing sources; and high-
emitting equipment and large boilers in Basic Chemical Manufacturing, 
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and 
Paperboard Mills. Refer to Table III.A-1 for a list of North American 
Industry Classification System (NAICS) codes for each entity included 
for regulation under this proposed rule.
3. Proposed Error Correction for Previously Approved 2015 Ozone 
Transport SIP
    The EPA proposes to make an error correction under CAA section 
110(k)(6) of its May 1, 2020, approval at 85 FR 25307 of the interstate 
transport elements for Delaware's October 11, 2018, and December 26, 
2019, ozone infrastructure SIP submissions as satisfying the 
requirements of CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone 
NAAQS. The EPA proposes to determine that the basis for the prior SIP 
approval is invalidated by the Agency's more recent technical 
evaluation of air quality modeling performed in support of the proposed 
rule,\10\ and that Delaware has unresolved interstate transport 
obligations for the 2015 ozone NAAQS. In this proposed rule, the EPA is 
also exercising its authority to propose to issue a FIP for Delaware in 
light of these unresolved interstate transport obligations.
---------------------------------------------------------------------------

    \10\ See the Air Quality Modeling Technical Support Document 
(AQM TSD) in the docket for this proposed rule.
---------------------------------------------------------------------------

4. Request for Comment on All Aspects of the Proposal
    Throughout this proposed rule, unless noted otherwise, the EPA is 
requesting comments on all aspects of the proposal to enable the Agency 
to develop a final rule that, consistent with our responsibilities 
under section 110 of the CAA, eliminates air pollution that 
significantly contributes to nonattainment or interference with 
maintenance of the 2015 ozone NAAQS. This proposed rule adheres closely 
to the legal and analytical framework that the EPA has applied in the 
past in implementing the good neighbor provision of the CAA, as well as 
the ample case law reviewing that framework. At the same time, in this 
proposal, the EPA is applying lessons learned from the performance of 
regulatory programs established by previous ozone transport 
rulemakings, as well as updating the Agency's application of the 4-step 
interstate transport framework with recent information on the nature of 
ozone transport and emissions reductions opportunities in order to 
eliminate significant contribution for the more stringent 2015 ozone 
NAAQS under the good neighbor provision. The EPA invites comments and 
information to support its efforts to improve the regulation of 
interstate ozone transport under the good neighbor provision and to 
fulfill our mission to protect human health and the environment. The 
EPA will carefully consider information provided in response to this 
request and will respond to comments submitted through the regulatory 
docket in the final rule.

B. Summary of the Major Provisions of the Regulatory Action

    The EPA is applying the 4-step interstate transport framework 
developed in CSAPR, the CSAPR Update, the Revised CSAPR Update, and 
other previous ozone transport rules to propose to further limit 
NOX emissions from EGU sources within the borders of 25 
states during the ozone season (May 1 through September 30) and to 
limit ozone season NOX emissions from non-EGU sources in 23 
states to reduce interstate ozone transport under the authority 
provided in CAA section 110(a)(2)(D)(i)(I). The 4-step interstate 
transport framework provides a stepwise method for the EPA to propose 
rule provisions that are required to address the requirements of the 
good neighbor provision for the 2015 ozone NAAQS: (1) Identifying 
downwind receptors that are expected to have problems attaining or

[[Page 20042]]

maintaining the NAAQS; (2) determining which upwind states contribute 
to these identified problems in amounts sufficient to ``link'' them to 
the downwind air quality problems (i.e., in this proposed rule, a 
contribution threshold of 1 percent of the NAAQS); (3) for states 
linked to downwind air quality problems, identifying upwind emissions 
that significantly contribute to downwind nonattainment or interfere 
with downwind maintenance of the NAAQS; and (4) for states that are 
found to have emissions that significantly contribute to nonattainment 
or interfere with maintenance of the NAAQS in downwind areas, 
implementing the necessary emissions reductions through enforceable 
measures. In this proposed rule, the EPA applies the 4-step framework 
to evaluate upwind states' obligations to reduce interstate transport 
of ozone precursor emissions for the 2015 ozone NAAQS. The remainder of 
this section provides a general overview of the EPA's application of 
the 4-step framework as it applies to major provisions of the proposed 
rule; additional details regarding EPA's proposed rule approach are 
found in Section IV of this proposed rule.
    In order to apply the first step of the 4-step framework to the 
2015 ozone NAAQS, the EPA performed air quality modeling to project 
ozone concentrations at air quality monitoring sites in 2023, 2026, and 
2032.\11\ The EPA evaluated projected ozone concentrations for the 2023 
analytic year at individual monitoring sites and considered current 
ozone monitoring data at these sites to identify receptors that are 
anticipated to have problems attaining or maintaining the 2015 ozone 
NAAQS. This analysis was then repeated using projected ozone 
concentrations for 2026 and 2032.
---------------------------------------------------------------------------

    \11\ These 3 analytic years are the last full ozone seasons 
before, and thus align with, upcoming attainment dates for the 2015 
ozone NAAQS: August 3, 2024, for areas classified as Moderate 
nonattainment, August 3, 2027, for areas classified as Serious 
nonattainment, and August 3, 2033, for areas classified as Severe. 
See 83 FR 25776.
---------------------------------------------------------------------------

    To apply the second step of the framework, the EPA used air quality 
modeling to quantify the contributions from upwind states to ozone 
concentrations in 2023 and 2026 at downwind receptors.\12\ Once 
quantified, EPA then evaluated these contributions relative to a 
screening threshold of 1 percent of the NAAQS (i.e., 0.70 ppb).\13\ 
States with contributions that equaled or exceeded 1 percent of the 
NAAQS were identified as warranting further analysis at Step 3 of the 
four-step framework to determine if the upwind state significantly 
contributes to nonattainment or interference with maintenance in a 
downwind state. States with contributions below 1 percent of the NAAQS 
were considered not to significantly contribute to nonattainment or 
interfere with maintenance of the NAAQS in downwind states. Based on 
EPA's most recent air quality modeling and contribution analysis using 
2023 as the analytic year, the EPA proposes to find that the following 
27 states have contributions that equal or exceed 1 percent of the 2015 
ozone NAAQS, and, thereby, warrant further analysis of significant 
contribution to nonattainment or interference with maintenance of the 
NAAQS: Alabama, Arkansas, California, Delaware, Illinois, Indiana, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Oregon, 
Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming. Further evaluation of the locations in 
California to which Oregon was linked at Step 2 leads the EPA to 
conclude downwind areas represented by these monitoring sites should 
not be considered interstate ozone transport receptors. Therefore, the 
EPA is not proposing any further emissions reductions from the state of 
Oregon because there is no significant contribution required to be 
eliminated under the interstate transport provision, as described in 
Section V.F of this proposed rule.
---------------------------------------------------------------------------

    \12\ The EPA did not perform contribution modeling for 2032 
since contribution data for this year were not needed to identify 
upwind states to be analyzed in Step 3.
    \13\ See Section V of this proposed rule for explanation of 
EPA's use of the 1 percent of the NAAQS threshold in the Step 2 
analysis.
---------------------------------------------------------------------------

    Based on the air quality analysis presented in Section V of this 
proposed rule, the EPA proposes to find that in the absence of 
additional emissions reductions in those states the majority of the 
states that the EPA is proposing to participate in the Ozone Season 
Group 3 Trading Program will continue to contribute above the 1 percent 
of the NAAQS threshold to at least one receptor whose nonattainment and 
maintenance concerns persist through the 2026 ozone season, with the 
exception of Alabama, Delaware, and Tennessee. As a result, EPA's 
evaluation of emissions reduction potential at Step 3 for Alabama, 
Delaware, and Tennessee is limited to emission reductions achievable by 
the 2023 ozone season. For each of these three states, EPA's analysis 
does not consider, nor does the EPA propose to require, emissions 
reductions at either EGUs or non-EGUs that cannot be implemented until 
the 2026 ozone season.
    At the third step of the 4-step framework, EPA applied a multi-
factor test that incorporates cost, availability of emissions 
reductions, and air quality impacts at the downwind receptors to 
determine the amount of ozone precursor emissions from the linked 
upwind states that ``significantly'' contribute to downwind 
nonattainment or maintenance receptors. In this proposed rule, the EPA 
proposes to apply the multifactor test described in Section VI.A of 
this proposed rule to both EGU and non-EGU sources. The EPA assessed 
the potential emissions reductions in 2023 and 2026, as well as in 
intervening and later years to determine the emissions reductions 
required to eliminate significant contribution in any future year where 
downwind areas are projected to have potential problems attaining or 
maintaining the 2015 ozone NAAQS.
    For EGU sources, the EPA evaluated the following set of widely-
available NOX emissions control technologies: (1) Fully 
operating existing selective catalytic reduction (SCR) controls, 
including both optimizing NOX removal by existing 
operational SCRs and turning on and optimizing existing idled SCRs; (2) 
installing state-of-the-art NOX combustion controls; (3) 
fully operating existing selective non-catalytic reduction (SNCR) 
controls, including both optimizing NOX removal by existing 
operational SNCRs and turning on and optimizing existing idled SNCRs; 
(4) installing new SNCRs; (5) installing new SCRs; and (6) generation 
shifting. For the reasons explained in Section VI of this proposed rule 
and supported by the EGU NOX Mitigation Strategies Proposed 
Rule Technical Support Document (TSD) included in the docket for this 
proposed rule, the EPA determined that for the regional, multi-state 
scale of this rulemaking, only fully operating and optimizing existing 
SCRs and existing SNCRs (EGU NOX emissions controls options 
1 and 3 in the list earlier) are possible for the 2023 ozone season. 
The EPA determined that state-of-the-art NOX combustion 
controls at EGUs (emissions control option 2 in the list above) are 
available by the beginning of the 2024 ozone season. Based on EPA's 
assessment of the earliest possible timeframe for installation of new 
SNCR and SCRs (EGU emissions controls options 4 and 5 in the list), the 
EPA proposes to require emissions reductions commensurate with these 
controls by the beginning of the 2026 ozone season. See Section VI.B.1 
of this proposed rule for a full description of

[[Page 20043]]

EPA's analysis of NOX emissions mitigation strategies for 
EGU sources.
    The EPA proposes control stringency levels that maximize 
incremental NOX emissions reduction potential from EGUs and 
corresponding downwind ozone air quality improvements to the extent 
feasible in each year analyzed. The EPA believes that the required 
controls provide cost-effective reductions of NOX emissions 
that will provide substantial improvements in downwind ozone air 
quality to address interstate transport obligations for the 2015 ozone 
NAAQS in a timely manner. These controls represent greater stringency 
in upwind EGU controls than in EPA's most recent ozone transport 
rulemakings, such as the CSAPR Update and the Revised CSAPR Update. 
However, programs to address interstate ozone transport based on the 
retrofit of post-combustion controls are by no means unprecedented. In 
prior ozone transport rulemakings such as the NOX SIP Call 
and the Clean Air Interstate Rule (CAIR), the EPA established EGU 
budgets premised on the widespread availability of retrofitting EGUs 
with post-combustion emissions controls such as SCR.\14\ While these 
programs successfully drove many EGUs to retrofit post-combustion 
controls, other EGUs throughout the present geography of linked upwind 
states continue to operate without such controls and continue to emit 
at relatively high rates more than 20 years after similar units reduced 
these emissions under prior interstate ozone transport rulemakings.
---------------------------------------------------------------------------

    \14\ See, e.g., 70 FR 25162, 25205-06 (May 12, 2005).
---------------------------------------------------------------------------

    Furthermore, the CSAPR Update provided only a partial remedy for 
eliminating significant contribution for the 2008 ozone NAAQS, as 
needed to obtain available reductions by the 2017 ozone season. In that 
rule, the EPA made no determination regarding the appropriateness of 
more stringent EGU NOX controls that would be required for a 
full remedy for interstate transport for the 2008 ozone NAAQS. 
Following the remand of the CSAPR Update in Wisconsin v. EPA, 938 F.3d 
303 (D.C. Cir. 2019) (Wisconsin), the EPA again declined to require the 
retrofit of new post-combustion controls on EGUs in the Revised CSAPR 
Update, but that determination was based on a specific timing 
consideration: Downwind air quality problems under the 2008 ozone NAAQS 
were projected to resolve before post-combustion control retrofits 
could be accomplished on a fleetwide, regional scale. See 86 FR 23054, 
23110 (April 30, 2021).
    In this proposed rulemaking, the EPA is addressing good neighbor 
obligations for the more stringent 2015 ozone NAAQS, and the Agency 
observes ongoing and persistent contribution from upwind states to 
ozone nonattainment and maintenance receptors in other states under 
that NAAQS. As further discussed in Section VI of this proposed rule, 
the nature of this contribution warrants a greater degree of control 
stringency than the EPA determined to be necessary to eliminate 
significant contribution of ozone transport in prior CSAPR rulemakings. 
The EPA is therefore returning to EGU NOX control strategies 
commensurate with those determined to be necessary in the 
NOX SIP Call and CAIR.
    Based on the Step 3 analysis described in Section VI of this 
proposed rule, the EPA is proposing that emissions reductions 
commensurate with the full operation of all existing post-combustion 
controls (both SCRs and SNCRs) and state-of-the-art combustion control 
upgrades constitute the Agency's selected control stringency for EGUs 
within the borders of 25 states linked to downwind nonattainment or 
maintenance in 2023 (Alabama, Arkansas, Delaware, Illinois, Indiana, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, 
Tennessee, Texas, Utah, Virginia, West Virginia, Wisconsin, and 
Wyoming). For 22 of those states that are also linked in 2026 
(Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming), the EPA is determining that the selected EGU 
control stringency also includes emissions reductions commensurate with 
the retrofit of SCR at coal steam units of 100 MW or greater capacity 
(excepting circulating fluidized bed units (CFB)), new SNCR on coal 
steam units of less than 100 MW capacity and CFBs, and SCR on oil/gas 
steam units greater than 100 MW that have historically emitted at least 
150 tons of NOX per ozone season.
    To identify appropriate control strategies for non-EGU sources to 
achieve NOX emissions reductions that would result in 
meaningful air quality improvements in downwind areas, the EPA 
developed an analytical framework to evaluate the air quality impacts 
of potential emissions reductions from non-EGU sources located in the 
linked upwind states. The EPA incorporated air quality modeling 
information, annual emissions, and information about potential controls 
to determine which industries, if subject to further control 
requirements, would have the greatest impact in providing air quality 
improvements at the downwind receptors. This evaluation was subject to 
a marginal cost threshold of up to $7,500 per ton, which the EPA 
determined based on information available to the Agency about existing 
control device efficiency and cost information. Additional information 
on the analytical framework is described in Section VI.B.2 of this 
proposed rule and is presented in the memorandum titled Screening 
Assessment of Potential Emissions Reductions, Air Quality Impacts, and 
Costs from Non-EGU Emissions Units for 2026 (``Non-EGU Screening 
Assessment memorandum''), which is available in the docket for this 
proposed rulemaking. Based on the results of this assessment, the EPA 
identified emissions unit types in seven industries (identified in 
Section I.A.2 of this proposed rule) that provide opportunities for 
NOX emissions reductions that result in meaningful impacts 
on air quality at the downwind receptors.
    The EPA performed air quality analysis using the Ozone Air Quality 
Assessment Tool (AQAT) to determine whether the proposed emissions 
reductions for both EGUs and non-EGUs potentially create an ``over-
control'' scenario whereby (1) the expected ozone improvements would be 
greater than necessary to resolve the downwind ozone pollution problem 
(i.e., beyond what is necessary to resolve all nonattainment and 
maintenance problems to which an upwind state is linked) or (2) the 
expected ozone improvements would reduce the upwind state's ozone 
contributions below the screening threshold (i.e., 1 percent of the 
NAAQS or 0.70 ppb). The EPA's over-control analysis, discussed in 
Section VI.D.4 of this proposed rule, shows that the proposed control 
stringencies for EGU and non-EGU sources do not over-control upwind 
states' emissions either with respect to the downwind air quality 
problems to which they are linked or with respect to the 1 percent of 
the NAAQS contribution threshold, such that over-control would trigger 
re-evaluation at Step 3 for any linked upwind state.

[[Page 20044]]

    Based on the multi-factor test applied to both EGU and non-EGU 
sources and our subsequent assessment of over-control, the EPA finds 
that the selected EGU and non-EGU control stringencies constitute the 
elimination of significant contribution and interference with 
maintenance, without over-controlling emissions, from the 26 upwind 
states subject to EGU and non-EGU emissions reductions requirements 
under the proposed rule. In order to eliminate significant contribution 
and interference with maintenance through the fourth step of the 4-step 
framework, as described in Section VII of this proposed rule, the EPA 
is establishing emissions budgets for EGUs within the borders of 25 
states that reflect the remaining allowable emissions after the 
emissions reductions associated with the selected control stringency 
have been achieved. For the same reason, the EPA is establishing non-
EGU emissions limits in 23 states that result in the elimination of 
significant contribution from non-EGU sources in these states. For 
additional details about the test and the over-control analysis, see 
the document titled, ``Ozone Transport Policy Analysis Proposed Rule 
TSD'' included in the docket for this rulemaking.
    In this fourth step of the 4-step framework, the EPA proposes to 
include enforceable measures in the promulgated FIPs to achieve the 
required emissions reductions in each of the 26 states. Specifically, 
the FIPs would require covered power plants within the borders of the 
25 states listed in Table I.A-1 to participate in the CSAPR 
NOX Ozone Season Group 3 Trading Program created by the 
Revised CSAPR Update. Affected EGUs within the borders of twelve states 
currently participating in the Group 3 Trading Program would remain in 
the program, with revised provisions beginning in the 2023 ozone 
season, under this proposed rule: Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, 
Pennsylvania, Virginia, and West Virginia. Affected EGUs within the 
borders of eight states currently covered by the CSAPR NOX 
Ozone Season Group 2 Trading Program (the ``Group 2 trading 
program'')--Alabama, Arkansas, Mississippi, Missouri, Oklahoma, 
Tennessee, Texas, and Wisconsin--would transition from the Group 2 
program to the revised Group 3 trading program beginning with the 2023 
control period,\15\ and affected EGUs within the borders of five states 
not currently covered by any CSAPR trading program for seasonal 
NOX emissions--Delaware, Minnesota, Nevada, Utah, and 
Wyoming--would enter the Group 3 trading program in the 2023 control 
period following the effective date of the final rule. In addition, the 
EPA proposes to revise other aspects of the Group 3 trading program to 
help maintain control stringency over time and improve emissions 
performance at individual units, offering a necessary measure of 
assurance that existing pollution controls will be operated during the 
ozone season, as described in Section VII of this proposed rule. This 
proposal does not revise the budget stringency and geography of the 
existing CSAPR NOX Ozone Season Group 1 trading program. 
Aside from the eight states moving from the Group 2 trading program to 
the Group 3 trading program under the proposed rule, this proposal 
otherwise leaves unchanged the budget stringency of the existing CSAPR 
NOX Ozone Season Group 2 trading program.
---------------------------------------------------------------------------

    \15\ The EPA would deem participation in the Group 3 trading 
program by the EGUs in these eight states as also addressing the 
respective states' good neighbor obligations with respect to the 
2008 ozone NAAQS (for all eight states), the 1997 ozone NAAQS (for 
all the states except Texas), and the 1979 ozone NAAQS (for Alabama, 
Missouri, and Tennessee) to the same extent that those obligations 
are currently being addressed by participation of the states' EGUs 
in the Group 2 trading program.
---------------------------------------------------------------------------

    The EPA is proposing preset ozone season NOX emissions 
budgets for the 2023 and 2024 ozone seasons, as explained in Section 
VII.B of this proposed rule and as shown in Table I.B-1.

 Table I.B-1--Proposed and Illustrative CSAPR NOX Ozone Season Group 3 State Emissions Budgets for 2023 Through
                                             2026 Control Periods *
----------------------------------------------------------------------------------------------------------------
                                                     Proposed        Proposed      Illustrative    Illustrative
                                                     emissions       emissions       emissions       emissions
                      State                         budgets for     budgets for     budgets for     budgets for
                                                   2023 control    2024 control    2025 control    2026 control
                                                   period (tons)   period (tons)   period (tons)   period (tons)
----------------------------------------------------------------------------------------------------------------
Alabama.........................................           6,364           6,306           6,306           6,306
Arkansas........................................           8,889           8,889           8,889           3,923
Delaware........................................             384             434             434             434
Illinois........................................           7,364           7,463           7,463           6,115
Indiana.........................................          11,151           9,391           8,714           7,791
Kentucky........................................          11,640          11,640          11,134           7,573
Louisiana.......................................           9,312           9,312           9,179           3,752
Maryland........................................           1,187           1,187           1,187           1,189
Michigan........................................          10,718          10,718          10,759           6,114
Minnesota.......................................           3,921           3,921           3,910           2,536
Mississippi.....................................           5,024           4,400           4,400           1,914
Missouri........................................          11,857          11,857          10,456           7,246
Nevada..........................................           2,280           2,372           2,372           1,211
New Jersey......................................             799             799             799             799
New York........................................           3,763           3,763           3,763           3,238
Ohio............................................           8,369           8,369           8,369           8,586
Oklahoma........................................          10,265           9,573           9,393           4,275
Pennsylvania....................................           8,855           8,855           8,855           6,819
Tennessee.......................................           4,234           4,234           4,008           4,008
Texas...........................................          38,284          38,284          36,619          21,946
Utah............................................          14,981          15,146          15,146           2,620
Virginia........................................           3,090           2,814           2,948           2,567
West Virginia...................................          12,478          12,478          12,478          10,597
Wisconsin.......................................           5,963           5,057           4,198           3,473

[[Page 20045]]

 
Wyoming.........................................           9,125           8,573           8,573           4,490
----------------------------------------------------------------------------------------------------------------
* Further information on the state-level emissions budget calculations pertaining to Table I.B-1 is provided in
  Section VII.B.4 of this proposed rule as well as the Ozone Transport Policy Analysis Proposed Rule TSD.
  Further information on the proposed approach for allocating a portion of Utah's emissions budget for each
  control period to the existing EGU in the Uintah and Ouray Reservation within Utah's borders is provided in
  Section VII.B.9 of this proposed rule.

    Beyond preset emissions budgets for the 2023 and 2024 control 
periods, the EPA also proposes to extend the Group 3 trading program 
budget-setting methodology used in the Revised CSAPR Update so as to 
routinely set emissions budgets for each future control period 
(beginning in 2025) in the year before that control period, with each 
emissions budget reflecting the latest available information on the 
composition and utilization of the EGU fleet at the time that emissions 
budget is determined (see Table VII.B.4.c-2 for illustrative examples 
of dynamic budget calculations that the EPA will publish in advance of 
each ozone season, effective for the 2025 control period and beyond). 
The stringency of the dynamic emissions budgets would simply reflect 
the stringency of the emissions control strategies selected in the 
rulemaking more consistently over time and ensure that the annual 
updates would eliminate emissions determined to be unlawful under the 
good neighbor provision. See Section VII.B of this proposed rule for 
additional discussion of EPA's proposed method for adjusting emissions 
budgets to ensure elimination of significant contribution from EGU 
sources in the linked upwind states.
    As an enhancement to the structure of the trading program as 
originally promulgated in the Revised CSAPR Update, the EPA is also 
proposing to establish backstop daily emissions rates for coal steam 
units greater than or equal to 100 MW in covered states. Units emitting 
in excess of these daily rates would be subject to increased allowance 
surrender requirements under the trading program. The backstop daily 
emissions rates would work in tandem with the ozone season emissions 
budgets to offer downwind stakeholders a necessary measure of assurance 
that they will be protected on a daily basis during the ozone season by 
continuous operation of installed pollution controls. The EPA's 
experience with the CSAPR trading programs has revealed instances where 
EGUs have reduced their SCRs' performance on a given day, or across the 
entire ozone seasons in some cases, including high ozone days.\16\ In 
addition to maintaining a mass-based seasonal requirement, the EPA 
proposes to require controls while maintaining as much compliance 
flexibility as possible through a unit-level emission rate designed to 
ensure that controls operate continuously and that required reductions 
occur on the highest ozone days. These trading program improvements 
also promote consistent emissions control performance across the power 
sector, which protects communities living in downwind ozone 
nonattainment areas from exceedances of the NAAQS that might otherwise 
occur.
---------------------------------------------------------------------------

    \16\ See 86 FR 23090. The EPA highlighted the Miami Fort Unit 7 
(possessing a SCR) more than tripled its ozone-season NOX 
emission rate between 2017 and 2019.
---------------------------------------------------------------------------

    The EPA proposes to include enforceable emissions standards that 
will apply during the ozone season (annually from May to September) for 
seven non-EGU industries in the promulgated FIPs to achieve the 
required emissions reductions in 23 states with remaining interstate 
transport obligations for the 2015 ozone NAAQS in 2026: Arkansas, 
California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming. These requirements would apply to all existing 
emissions units and to any future emissions units constructed in the 
covered states after promulgation of the final rule. Thus, the 
emissions limits for non-EGU sources and associated compliance 
requirements would apply in all 23 states listed in this paragraph, 
even if certain of these states do not currently have existing 
emissions units within a particular industry.
    Based on our evaluation of the time required to install controls at 
the types of non-EGU sources covered by this proposed rule, the EPA has 
identified the 2026 ozone season as the earliest compliance date 
possible for non-EGU emissions reductions. The EPA is therefore 
proposing to include non-EGU emissions reductions beginning in 2026. 
For sources located in the 23 states listed in the previous paragraph, 
The EPA proposes to require the emissions limits listed in Table I.B-2 
for

[[Page 20046]]

reciprocating internal combustion engines in Pipeline Transportation of 
Natural Gas; the emissions limits listed in Table I.B-3 for kilns in 
Cement and Cement Product Manufacturing; the emissions limits listed in 
Table I.B-4 for boilers and furnaces in Iron and Steel Mills and 
Ferroalloy Manufacturing; the emissions limits listed in Table I.B-5 
for furnaces in Glass and Glass Product Manufacturing; and the 
emissions limits listed in Table I.B-6 for high-emitting equipment and 
large boilers in Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, and Pulp, Paper, and Paperboard Mills.
---------------------------------------------------------------------------

    \17\ Based on source cap equation at 30 TAC Sec.  117.3123(b); 
January 14, 2009 (74 FR 1927), Docket ID No. EPA-R06-OAR-2007-1147, 
also see https://wayback.archive-it.org/414/20210527223433/https://www.tceq.texas.gov/assets/public/legal/rules/rules/pdflib/117e.pdf.

   Table I.B-2--Summary of Proposed NOX Emissions Limits for Pipeline
                      Transportation of Natural Gas
------------------------------------------------------------------------
                                           Proposed NOX emissions limit
          Engine type and fuel
------------------------------------------------------------------------
Natural Gas Fired Four Stroke Rich Burn.  1.0 g/hp-hr.
Natural Gas Fired Four Stroke Lean Burn.  1.5 g/hp-hr.
Natural Gas Fired Two Stroke Lean Burn..  3.0 g/hp-hr.
------------------------------------------------------------------------


 Table I.B-3--Summary of Proposed NOX Emissions Limits for Kiln Types in
                Cement and Concrete Product Manufacturing
------------------------------------------------------------------------
                                                           Proposed NOX
                                                             emissions
                        Kiln type                          limit (lb/ton
                                                           of  clinker)
 
------------------------------------------------------------------------
Long Wet................................................             4.0
Long Dry................................................             3.0
Preheater...............................................             3.8
Precalciner.............................................             2.3
Preheater/Precalciner...................................             2.8
------------------------------------------------------------------------

    The EPA is also proposing a source cap limit expressed in ton per 
day (tpd) of NOX for each individual cement plant according 
to the following equation.\17\
[GRAPHIC] [TIFF OMITTED] TP06AP22.000

Where:

CAP2015 Ozone Transport = total allowable NOX emissions 
from all cement kilns located at one cement plant, in tons per day, 
on a 30-operating day rolling average basis;
KD = 1.7 pounds NOX per ton of clinker for dry preheater-
precalciner or precalciner kilns;
KW = 3.4 pounds NOX per ton of clinker for long wet 
kilns;
ND = the average annual production in tons of clinker plus one 
standard deviation for the three most recent calendar years from all 
dry preheater-precalciner or precalciner kilns located at one cement 
plant; and
NW = the average annual production in tons of clinker plus one 
standard deviation for the 3 most recent calendar years from all 
long wet kilns located at one cement plant.

    An affected cement plant will need to comply with both the source 
cap limit and the specific NOX emissions limits assigned to 
its individual kiln type(s). Refer to Section VII.C.2 of this proposed 
rule for additional information concerning the application of the 
source cap limit to this industry source group.

Table I.B-4--Summary of Proposed NOX Emissions Limits for Iron and Steel
                     and Ferroalloy Emissions Units
------------------------------------------------------------------------
                                         Proposed NOX emissions standard
             Emissions unit              or requirement (lbs/hour or lb/
                                                      mmBtu)
------------------------------------------------------------------------
Blast Furnace..........................  0.03 lb/mmBtu.
Basic Oxygen Furnace...................  0.07 lb/ton.
Electric Arc Furnace...................  0.15 lb/ton steel.
Ladle/tundish Preheaters...............  0.06 lb/mmBtu.
Reheat furnace.........................  0.05 lb/mmBtu.
Annealing Furnace......................  0.06 lb/mmBtu.
Vacuum Degasser........................  0.03 lb/mmBtu.
Ladle Metallurgy Furnace...............  0.1 lb/ton.
Taconite production kilns..............  Work practice standard to
                                          install low NOX technology/
                                          burners, test and set.
Coke ovens (charging and coking).......  0.6 lb/ton of coal charged.
Coke ovens (pushing)...................  0.015 lb/ton of coal pushed.
Boilers--Coal..........................  0.20 lb/mmBtu.
Boilers--Residual oil..................  0.20 lb/mmBtu.
Boilers--Distillate oil................  0.12 lb/mmBtu.
Boilers--Natural gas...................  0.08 lb/mmBtu.
------------------------------------------------------------------------


[[Page 20047]]


 Table IV.B-5--Summary of Proposed NOX Emissions Limits for Furnace Unit
             Types in Glass and Glass Product Manufacturing
------------------------------------------------------------------------
                                                         Proposed NOX
                                                        emissions limit
                    Furnace type                       (lb/ton of glass
                                                           produced)
------------------------------------------------------------------------
Container Glass Manufacturing Furnace...............                 4.0
Pressed/Blown Glass Manufacturing Furnace or                         4.0
 Fiberglass Manufacturing Furnace...................
Flat Glass Manufacturing Furnace....................                 9.2
------------------------------------------------------------------------


 Table I.B-6--Summary of Proposed NOX Emissions Limits for High-Emitting
 Equipment and Large Boilers in Basic Chemical Manufacturing, Petroleum
 and Coal Products Manufacturing, and Pulp, Paper, and Paperboard Mills
------------------------------------------------------------------------
                                                             Emissions
                        Unit type                         limit (lbs NOX/
                                                              mmBtu)
------------------------------------------------------------------------
Coal....................................................            0.20
Residual oil............................................            0.20
Distillate oil..........................................            0.12
Natural gas.............................................            0.08
------------------------------------------------------------------------

    Refer to Section VII.C of this proposed rule for applicability 
criteria, compliance assurance requirements, and the EPA's rationale in 
proposing these emissions limits for each of the non-EGU industries 
covered by the proposed rule. In addition, the EPA requests comment on 
several topics regarding the implementation of emissions limits for 
non-EGU sources that are proposed in this rulemaking, including 
controls on emissions units and control installation timing. See 
Section VI.D.2.a of this proposed rule for a list of detailed questions 
on which the Agency is soliciting public comment.
    The remainder of this preamble is organized as follows: Section III 
of this proposed rule outlines general applicability criteria for the 
proposed rule and describes the EPA's legal authority for this proposed 
rule, the relationship of the proposed rule to previous interstate 
ozone transport rulemakings, and the incremental costs and benefits of 
the proposed rule; Section IV of this proposed rule describes the human 
health and environmental challenges posed by interstate transport 
contributions to ozone air quality problems, as well as EPA's overall 
approach for addressing interstate transport for the 2015 ozone NAAQS 
in this proposed rule; Section V of this proposed rule describes the 
Agency's analyses of air quality data to inform this proposed 
rulemaking, including descriptions of the air quality modeling platform 
and emissions inventories used in the proposed rule, as well as EPA's 
methods for identifying downwind air quality problems and upwind 
states' ozone transport contributions to downwind states; Section VI of 
this proposed rule describes EPA's approach to quantifying upwind 
states' obligations in the form of EGU NOX control 
stringencies and non-EGU emissions limits; Section VII of this proposed 
rule describes key elements of the implementation schedule for EGU and 
non-EGU emissions reductions requirements, including details regarding 
the revised aspects of the CSAPR NOX Group 3 trading program 
and compliance deadlines, as well as regulatory requirements and 
compliance deadlines for non-EGU sources; Section VIII of this proposed 
rule discusses the environmental justice considerations of the proposed 
rule; Section IX of this proposed rule describes the expected costs, 
benefits, and other impacts of this proposed rule; Section X of this 
proposed rule provides a summary of proposed changes to the existing 
regulatory text; and Section XI of this proposed rule discusses the 
statutory and executive orders affecting this proposed rulemaking.

C. Costs and Benefits

    A summary of the key results of the cost-benefit analysis that was 
prepared for this proposed rule is presented in Table I.C-1. Table I.C-
1 presents estimates of the present values (PV) and equivalent 
annualized values (EAV), calculated using discount rates of 3 and 7 
percent as directed by OMB's Circular A-4, of the health benefits, 
compliance costs, and net benefits of the proposed rule, in 2016 
dollars, discounted to 2022. The estimated monetized net benefits are 
the estimated monetized benefits minus the estimated monetized costs of 
the proposed rule. These results present an incomplete overview of the 
effects of the proposal, because important categories of benefits--
including benefits from reducing climate pollution, other types of air 
pollutants, and water pollution--were not monetized and are therefore 
not reflected in the cost-benefit tables. We anticipate that taking 
non-monetized effects into account would show the proposal to be more 
net beneficial than this table reflects.

  Table I.C-1--Estimated Monetized Benefits, Compliance Costs, and Net
            Benefits of the Proposed Rule, 2023 Through 2042
                 [Millions 2016$, discounted to 2022] a
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
Present Value:
    Benefits \b\................             250,000             150,000
    Compliance Costs \c\........              22,000              14,000
                                 ---------------------------------------
        Net Benefits............             220,000             130,000
------------------------------------------------------------------------
Equivalent Annualized Value:
    Benefits....................              17,000              14,000
    Compliance Costs............               1,500               1,300
                                 ---------------------------------------

[[Page 20048]]

 
              Net Benefits......              15,000              12,000
------------------------------------------------------------------------
\a\ Rows may not appear to add correctly due to rounding.
\b\ The annualized present value of costs and benefits are calculated
  over a 20-year period from 2023 to 2042. Monetized benefits include
  those related to public health associated with reductions in PM2.5 and
  ozone concentrations. The health benefits are associated with several
  point estimates and are presented at real discount rates of 3 and 7
  percent. Several categories of benefits remain unmonetized and are
  thus not reflected in the table. Non-monetized benefits include
  important climate benefits from reductions in CO2 emissions. The U.S.
  District Court for the Western District of Louisiana has issued an
  injunction concerning the monetization of the benefits of greenhouse
  gas emission reductions by EPA and other defendants. See Louisiana v.
  Biden, No. 21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore,
  such values are not presented in the benefit-cost analysis of this
  proposal conducted pursuant to E.O. 12866. Please see Chapter 5,
  Section 5.2 of the RIA for more discussion. In addition, there are
  important unquantified water quality benefits and benefits associated
  with reductions in other air pollutants.
\c\ The costs presented in this table are consistent with the costs
  presented in Chapter 4 of the RIA. To estimate these annualized costs,
  EPA uses a conventional and widely accepted approach that applies a
  capital recovery factor (CRF) multiplier to capital investments and
  adds that to the annual incremental operating expenses. Costs were
  calculated using a 3.76% real discount rate consistent with the rate
  used in IPM's objective function for cost-minimization.

    As shown in Table I.C-1, the PV of the benefits, associated with 
reductions in PM2.5 and ozone concentrations, of this 
proposed rule, discounted at a 3-percent discount rate, is estimated to 
be about $250,000 million, with an EAV of about $17,000 million. At a 
7-percent discount rate, the PV of the benefits is estimated to be 
$150,000 million, with an EAV of about $14,000 million. The PV of the 
compliance costs, discounted at a 3-percent rate, is estimated to be 
about $22,000 million, with an EAV of about $1,500 million. At a 7-
percent discount rate, the PV of the compliance costs is estimated to 
be about $14,000 million, with an EAV of about $1,300 million.

II. Public Participation

A. Written Comments

    Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2021-
0668 at https://www.regulations.gov (our preferred method), or the 
other methods identified in the ADDRESSES section. Once submitted, 
comments cannot be edited or removed from the docket. The EPA may 
publish any comment received to its public docket. Do not submit to 
EPA's docket at https://www.regulations.gov 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, the full EPA public comment 
policy, information about CBI or multimedia submissions, and general 
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
    Due to public health concerns related to COVID-19, the EPA Docket 
Center and Reading Room are open to the public by appointment only. Our 
Docket Center staff also continues to provide remote customer service 
via email, phone, and webform. Hand deliveries or couriers will be 
received by scheduled appointment only. For further information and 
updates on EPA Docket Center services, please visit us online at 
https://www.epa.gov/dockets.
    The EPA continues to carefully and continuously monitor information 
from the Centers for Disease Control and Prevention (CDC), local area 
health departments, and our Federal partners so that we can respond 
rapidly as conditions change regarding COVID-19.

B. Submitting Confidential Business Information

    Do not submit information containing CBI to the EPA through https://www.regulations.gov. Clearly mark the part or all of the information 
that you claim to be CBI. For CBI information on any digital storage 
media that you mail to the EPA, mark the outside of the digital storage 
media as CBI and then identify electronically within the digital 
storage media the specific information that is claimed as CBI. In 
addition to one complete version of the comments that includes 
information claimed as CBI, you must submit a copy of the comments that 
does not contain the information claimed as CBI directly to the public 
docket through the procedures outlined in Instructions earlier. If you 
submit any digital storage media that does not contain CBI, mark the 
outside of the digital storage media clearly that it does not contain 
CBI. Information not marked as CBI will be included in the public 
docket and the EPA's electronic public docket without prior notice. 
Information marked as CBI will not be disclosed except in accordance 
with procedures set forth in 40 Code of Federal Regulations (CFR) part 
2. Our preferred method to receive CBI is for it to be transmitted to 
electronically using email attachments, File Transfer Protocol (FTP), 
or other online file sharing services (e.g., Dropbox, OneDrive, Google 
Drive). Electronic submissions must be transmitted directly to the 
OAQPS CBI Office using the email address, [email protected], and should 
include clear CBI markings as described above. If assistance is needed 
with submitting large electronic files that exceed the file size limit 
for email attachments, and if you do not have your own file sharing 
service, please email [email protected] to request a file transfer link. 
If sending CBI information through the postal service, please send it 
to the following address: OAQPS Document Control Officer (C404-02), 
OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, 
North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2021-0668. The 
mailed CBI material should be double wrapped and clearly marked. Any 
CBI markings should not show through the outer envelope.

C. Participation in Virtual Public Hearing

    Please note that because of current CDC recommendations, as well as 
state and local orders for social distancing to limit the spread of 
COVID-19, the EPA cannot hold in-person public meetings at this time.
    The EPA will begin pre-registering speakers for the hearing no 
later than 1 business day after publication of this document in the 
Federal Register. To

[[Page 20049]]

register to speak at the virtual hearing, please use the online 
registration form available at https://www.epa.gov/csapr/csapr-2015-ozone-naaqs. The last day to pre-register to speak at the hearing will 
be April 21, 2022. The EPA will post a general agenda for the hearing 
that will list pre-registered speakers in approximate order at: https://www.epa.gov/csapr/csapr-2015-ozone-naaqs.
    The virtual public hearing will be held on via teleconference on 
April 21, 2022. The virtual public hearing will convene at 10:00 a.m. 
Eastern Time (ET) and will conclude at 7:00 p.m. ET. The EPA may close 
a session 15 minutes after the last pre-registered speaker has 
testified if there are no additional speakers. For information or 
questions about the public hearing, please contact Ms. Holly DeJong at 
[email protected]. The EPA will announce further details at https://www.epa.gov/csapr/csapr-2015-ozone-naaqs.
    The EPA will make every effort to follow the schedule as closely as 
possible on the day of the hearing; however, please plan for the 
hearings to run either ahead of schedule or behind schedule.
    Each commenter will have 5 minutes to provide oral testimony. The 
EPA encourages commenters to provide the EPA with a copy of their oral 
testimony electronically (via email) by emailing it to 
[email protected]. The EPA also recommends submitting the text of 
your oral comments as written comments to the rulemaking docket.
    The EPA may ask clarifying questions during the oral presentations, 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral comments and 
supporting information presented at the public hearing.
    Please note that any updates made to any aspect of the hearing will 
be posted online at https://www.epa.gov/csapr/csapr-2015-ozone-naaqs. 
While the EPA expects the hearing to go forward as set forth above, 
please monitor our website or contact Ms. Holly DeJong at 
[email protected] to determine if there are any updates. The EPA 
does not intend to publish a document in the Federal Register 
announcing updates.
    If you require the services of a translator or special 
accommodations such as audio description, please pre-register for the 
hearing and describe your needs by April 18, 2022. EPA may not be able 
to arrange accommodations without advanced notice.

III. General Information

A. Does this action apply to me?

    This proposed rule affects EGU and non-EGU sources, and regulates 
the groups identified in Table III.A-1.

                     Table III.A-1--Regulated Groups
------------------------------------------------------------------------
                        Industry group                            NAICS
------------------------------------------------------------------------
Fossil fuel-fired electric power generation...................    221112
Pipeline Transportation of Natural Gas........................      4862
Cement and Concrete Product Manufacturing.....................      3273
Iron and Steel Mills and Ferroalloy Manufacturing.............      3311
Glass and Glass Product Manufacturing.........................      3272
Basic Chemical Manufacturing..................................      3251
Petroleum and Coal Products Manufacturing.....................      3241
Pulp, Paper, and Paperboard Mills.............................      3221
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
proposed rule. This table lists the types of entities that the EPA is 
now aware could potentially be regulated by this proposed rule. Other 
types of entities not listed in the table could also be regulated. For 
example, the EPA is requesting comment in Section VI.B.3 of this 
proposed rule on potential control strategies for sources outside of 
the categories listed in the Table III.A.1, such as municipal waste 
combustors (MWCs). To determine whether your EGU entity is proposed to 
be regulated by this proposed rule, you should carefully examine the 
applicability criteria found in 40 CFR 97.1004, which the EPA is not 
proposing to alter in this proposed rule. If you have questions 
regarding the applicability of this proposed rule to a particular 
entity, consult the person listed in the FOR FURTHER INFORMATION 
CONTACT section.

B. What action is the Agency taking?

    The EPA evaluated whether interstate ozone transport emissions from 
upwind states are significantly contributing to nonattainment, or 
interfering with maintenance, of the 2015 ozone NAAQS in any downwind 
state using the same 4-step interstate transport framework that was 
developed in previous ozone transport rulemakings. The EPA is proposing 
to find that emissions reductions are required from EGU and non-EGU 
sources in a total of 26 upwind states to eliminate significant 
contribution to downwind air quality problems for the 2015 ozone 
standard under the interstate transport provision of the CAA. The EPA 
will ensure that these NOX emissions reductions are achieved 
by issuing proposed FIP requirements for 26 states: Alabama, Arkansas, 
California, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New 
York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, 
West Virginia, Wisconsin, and Wyoming.
    The EPA is proposing to revise the existing CSAPR Group 3 Trading 
Program to include additional states beginning in the 2023 ozone 
season. EGUs in five states not currently covered by any CSAPR trading 
program for seasonal NOX emissions--Delaware, Minnesota, 
Nevada, Utah, and Wyoming--would be added to the CSAPR Group 3 Trading 
Program under this proposed rule. EGUs in twelve states currently 
participating in the Group 3 Trading Program would remain in the 
program under this proposed rule: Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, 
Pennsylvania, Virginia, and West Virginia. EGUs in eight states 
(Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Tennessee, Texas, 
and Wisconsin) will transition from the CSAPR Group 2 Trading Program 
to the CSAPR Group 3 Trading Program under this proposed rule beginning 
in the 2023 ozone season. The EPA proposes to establish control 
stringency levels reflecting installation of state-of-the-art 
combustion controls on certain covered EGU sources in emissions budgets 
beginning in the 2024 ozone season. The EPA proposes to establish 
control stringency levels reflecting installation of new SCR or SNCR 
controls on certain covered EGU sources in emissions budgets beginning 
in the 2026 ozone season.
    As a complement to the ozone season emissions budgets, the EPA is 
also proposing to establish backstop daily emissions rates of 0.14 lb/
mmBtu for coal-fired steam units greater than or equal to 100 MW in 
covered states. The backstop emissions rates will first apply in 2024 
for coal-fired steam sources with existing SCRs, and in 2027 for those 
currently without SCRs.
    In this proposed rule, the EPA is proposing to require emissions 
limitations for non-EGU sources in 23 states: Arkansas, California, 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, West Virginia, Wisconsin, and

[[Page 20050]]

Wyoming. In these states, EPA is proposing to require emissions 
limitations for the following unit types in non-EGU industries: 
Furnaces in Glass and Glass Product Manufacturing; boilers and furnaces 
in Iron and Steel Mills and Ferroalloy Manufacturing; kilns in Cement 
and Cement Product Manufacturing; reciprocating internal combustion 
engines in Pipeline Transportation of Natural Gas; and high-emitting 
equipment and large boilers in Basic Chemical Manufacturing, Petroleum 
and Coal Products Manufacturing, and Pulp, Paper, and Paperboard Mill. 
See Table III.A-1 for a list of NAICS codes for each entity included 
for regulation under this proposed rule.
    The proposed rule would reduce the transport of ozone precursor 
emissions to downwind areas, which is protective of human health and 
the environment because acute and chronic exposure to ozone are both 
associated with negative health impacts. Ozone exposure is also 
associated with negative effects on ecosystems. Additional information 
on the human health and environmental benefits from the air quality 
issues addressed by this proposed rule are included in Section IV of 
this proposed rule.

C. What is the Agency's legal authority for taking this action?

1. Statutory Authority
    The statutory authority for this proposed rule is provided by the 
CAA as amended (42 U.S.C. 7401 et seq.). Specifically, sections 110 and 
301 of the CAA provide the primary statutory underpinnings for this 
proposed rule. The most relevant portions of CAA section 110 are 
subsections 110(a)(1), 110(a)(2) (including 110(a)(2)(D)(i)(I)), 
110(c)(1), and 110(k)(6)).
    CAA section 110(a)(1) provides that states must make SIP 
submissions ``within 3 years (or such shorter period as the 
Administrator may prescribe) after the promulgation of a national 
primary ambient air quality standard (or any revision thereof),'' and 
that these SIP submissions are to provide for the ``implementation, 
maintenance, and enforcement'' of such NAAQS.\18\ The statute directly 
imposes on states the duty to make these SIP submissions, and the 
requirement to make the submissions is not conditioned upon the EPA 
taking any action other than promulgating a new or revised NAAQS.\19\
---------------------------------------------------------------------------

    \18\ 42 U.S.C. 7410(a)(1).
    \19\ See EPA v. EME Homer City Generation, L.P., 572 U.S. 489, 
509-10 (2014).
---------------------------------------------------------------------------

    The EPA has historically referred to SIP submissions made for the 
purpose of satisfying the applicable requirements of CAA sections 
110(a)(1) and 110(a)(2) as ``infrastructure SIP'' or ``iSIP'' 
submissions. CAA section 110(a)(1) addresses the timing and general 
requirements for iSIP submissions, and CAA section 110(a)(2) provides 
more details concerning the required content of these submissions.\20\ 
It includes a list of specific elements that ``[e]ach such plan'' must 
address.\21\
---------------------------------------------------------------------------

    \20\ 42 U.S.C. 7410(a)(2).
    \21\ EPA's general approach to infrastructure SIP submissions is 
explained in greater detail in individual notices acting or 
proposing to act on state infrastructure SIP submissions and in 
guidance. See, e.g., Memorandum from Stephen D. Page on Guidance on 
Infrastructure State Implementation Plan (SIP) Elements under Clean 
Air Act Sections 110(a)(1) and 110(a)(2) (September 13, 2013).
---------------------------------------------------------------------------

    CAA section 110(c)(1) requires the Administrator to promulgate a 
FIP at any time within two years after the Administrator: (1) Finds 
that a state has failed to make a required SIP submission; (2) finds a 
SIP submission to be incomplete pursuant to CAA section 110(k)(1)(C); 
or (3) disapproves a SIP submission. This obligation applies unless the 
state corrects the deficiency through a SIP revision that the 
Administrator approves before the FIP is promulgated.\22\
---------------------------------------------------------------------------

    \22\ 42 U.S.C. 7410(c)(1).
---------------------------------------------------------------------------

    CAA section 110(a)(2)(D)(i)(I), also known as the ``good neighbor'' 
provision, provides the primary basis for this proposed rule.\23\ It 
requires that each state SIP include provisions sufficient to 
``prohibit[ ], consistent with the provisions of this subchapter, any 
source or other type of emissions activity within the State from 
emitting any air pollutant in amounts which will--(I) contribute 
significantly to nonattainment in, or interfere with maintenance by, 
any other State with respect to any [NAAQS].'' \24\ The EPA often 
refers to the emissions reduction requirements under this provision as 
``good neighbor obligations'' and submissions addressing these 
requirements as ``good neighbor SIPs.''
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    \23\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
    \24\ Id.
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    Once EPA promulgates a NAAQS, the EPA must designate areas as being 
in ``attainment'' or ``nonattainment'' of the NAAQS, or 
``unclassifiable.'' CAA section 107(d).\25\ For ozone, nonattainment is 
further split into five classifications based on the severity of the 
violation--Marginal, Moderate, Serious, Severe, or Extreme. Higher 
classifications provide states with progressively more time to attain 
while imposing progressively more stringent control requirements. See 
CAA sections 181, 182.\26\ In general, states with nonattainment areas 
classified as Moderate or higher must submit plans to EPA to bring 
these areas into attainment according to the statutory schedule. CAA 
section 182.\27\ If an area fails to attain the NAAQS by the attainment 
date associated with its classification, it is ``bumped up'' to the 
next classification. CAA section 181(b).\28\
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    \25\ 42 U.S.C. 7407(d).
    \26\ 42 U.S.C. 7511, 7511a.
    \27\ 42 U.S.C. 7511a.
    \28\ 42 U.S.C. 7511(b).
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    Section 301(a)(1) of the CAA gives the Administrator the general 
authority to prescribe such regulations as are necessary to carry out 
functions under the Act.\29\ Pursuant to this section, EPA has 
authority to clarify the applicability of CAA requirements and 
undertake other rulemaking action as necessary to implement CAA 
requirements. CAA section 301 affords the Agency any additional 
authority that may be needed in order to make certain other changes to 
its regulations under 40 CFR parts 52, 75, 78, and 97, in order to 
effectuate the purposes of the Act. Such changes are discussed in 
Section X of this proposed rule.
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    \29\ 42 U.S.C. 7601(a)(1).
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    Section 110(k)(6) of the CAA gives the Administrator authority, 
without any further submission from a state, to revise certain prior 
actions, including actions to approve SIPs, upon determining that those 
actions were in error.\30\ The EPA proposes to make an error correction 
under CAA section 110(k)(6) with respect to its prior approval of the 
2015 ozone transport SIP submission from the State of Delaware. This is 
further discussed in Section IV.C.1 of the proposed rule.
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    \30\ 42 U.S.C. 7410(k)(6).
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    Tribes are not required to submit state implementation plans. 
However, as explained in EPA's regulations outlining Tribal Clean Air 
Act authority, the EPA is authorized to promulgate FIPs for Indian 
country as necessary or appropriate to protect air quality if a tribe 
does not submit, and obtain EPA approval of, an implementation plan. 
See 40 CFR 49.11(a); see also CAA section 301(d)(4).\31\ In this 
proposed rule, the EPA proposes an ``appropriate or necessary'' finding 
under CAA section 301(d) and proposes tribal FIP(s) as necessary to 
implement the relevant requirements. This is further discussed in 
Section IV.C.2 of the proposed rule.
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    \31\ 42 U.S.C. 7601(d)(4).

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[[Page 20051]]

D. What actions has EPA previously issued to address regional ozone 
transport?

    The EPA has issued several major rules interpreting and clarifying 
the requirements of CAA section 110(a)(2)(D)(i)(I) with respect to the 
regional transport of ozone. These rules, and the associated court 
decisions addressing these rules, summarized here, provide important 
direction regarding the requirements of CAA section 110(a)(2)(D)(i)(I).
    The ``NOX SIP Call,'' promulgated in 1998, addressed the 
good neighbor provision for the 1979 1-hour ozone NAAQS.\32\ The rule 
required 22 states and the District of Columbia to amend their SIPs to 
reduce NOX emissions that contribute to ozone nonattainment 
in downwind states. The EPA set ozone season NOX budgets for 
each state, and the states were given the option to participate in a 
regional allowance trading program, known as the NOX Budget 
Trading Program.\33\ The D.C. Circuit largely upheld the NOX 
SIP Call in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000), cert. 
denied, 532 U.S. 904 (2001).
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    \32\ Finding of Significant Contribution and Rulemaking for 
Certain States in the Ozone Transport Assessment Group Region for 
Purposes of Reducing Regional Transport of Ozone, 63 FR 57356 (Oct. 
27, 1998). As originally promulgated, the NOX SIP Call 
also addressed good neighbor obligations under the 1997 8-hour ozone 
NAAQS, but EPA subsequently stayed and later rescinded the rule's 
provisions with respect to that standard. See 84 FR 8422 (March 8, 
2019).
    \33\ ``Allowance Trading,'' sometimes referred to as ``cap and 
trade,'' is an approach to reducing pollution that has been used 
successfully to protect human health and the environment. The design 
elements of EPA's most recent trading programs are discussed in 
Section VII.B.1.a of this proposed rule.
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    EPA's next rule addressing the good neighbor provision, the Clean 
Air Interstate Rule (CAIR), was promulgated in 2005 and addressed both 
the 1997 fine particulate matter (PM2.5) NAAQS and 1997 
ozone NAAQS.\34\ CAIR required SIP revisions in 28 states and the 
District of Columbia to reduce emissions of sulfur dioxide 
(SO2) or NOX--important precursors of regionally 
transported PM2.5 (SO2 and annual NOX) 
and ozone (summer-time NOX). As in the NOX SIP 
Call, states were given the option to participate in regional trading 
programs to achieve the reductions. When the EPA promulgated the final 
CAIR in 2005, the EPA also issued findings that states nationwide had 
failed to submit SIPs to address the requirements of CAA section 
110(a)(2)(D)(i) with respect to the 1997 PM2.5 and 1997 
ozone NAAQS.\35\ On March 15, 2006, the EPA promulgated FIPs to 
implement the emissions reductions required by CAIR.\36\ CAIR was 
remanded to EPA by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 
896 (D.C. Cir. 2008), modified on reh'g, 550 F.3d 1176. For more 
information on the legal issues underlying CAIR and the D.C. Circuit's 
holding in North Carolina, refer to the preamble of the CSAPR rule.\37\
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    \34\ Rule To Reduce Interstate Transport of Fine Particulate 
Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain 
Program; Revisions to the NOX SIP Call, 70 FR 25162 (May 
12, 2005).
    \35\ 70 FR 21147 (April 25, 2005).
    \36\ 71 FR 25328 (April 28, 2006).
    \37\ Federal Implementation Plans: Interstate Transport of Fine 
Particulate Matter and Ozone and Correction of SIP Approvals, 76 FR 
48208, 48217 (August 8, 2011).
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    In 2011, the EPA promulgated CSAPR to address the issues raised by 
the remand of CAIR. CSAPR addressed the two NAAQS at issue in CAIR and 
additionally addressed the good neighbor provision for the 2006 
PM2.5 NAAQS.\38\ CSAPR required 28 states to reduce 
SO2 emissions, annual NOX emissions, or ozone 
season NOX emissions that significantly contribute to other 
states' nonattainment or interfere with other states' abilities to 
maintain these air quality standards.\39\ To align implementation with 
the applicable attainment deadlines, the EPA promulgated FIPs for each 
of the 28 states covered by CSAPR. The FIPs require EGUs in the covered 
states to participate in regional trading programs to achieve the 
necessary emissions reductions. Each state can submit a good neighbor 
SIP at any time that, if approved by EPA, would replace the CSAPR FIP 
for that state.
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    \38\ 76 FR 48208.
    \39\ CSAPR was revised by several rulemakings after its initial 
promulgation in order to revise certain states' budgets and to 
promulgate FIPs for five additional states addressing the good 
neighbor obligation for the 1997 ozone NAAQS. See 76 FR 80760 
(December 27, 2011); 77 FR 10324 (February 21, 2012); 77 FR 34830 
(June 12, 2012).
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    CSAPR was the subject of an adverse decision by the D.C. Circuit in 
August 2012.\40\ However, this decision was reversed in April 2014 by 
the Supreme Court, which largely upheld the rule, including EPA's 
approach to addressing interstate transport in CSAPR. EPA v. EME Homer 
City Generation, L.P., 572 U.S. 489 (2014) (EME Homer City I). The rule 
was remanded to the D.C. Circuit to consider claims not addressed by 
the Supreme Court. Id. In July 2015 the D.C. Circuit generally affirmed 
EPA's interpretation of various statutory provisions and EPA's 
technical decisions. EME Homer City Generation, L.P. v. EPA, 795 F.3d 
118 (2015) (EME Homer City II). However, the court remanded the rule 
without vacatur for reconsideration of EPA's emissions budgets for 
certain states, which the court found may have over-controlled those 
states' emissions with respect to the downwind air quality problems to 
which the states were linked. Id. at 129-30, 138. For more information 
on the legal issues associated with CSAPR and the Supreme Court's and 
D.C. Circuit's decisions in the EME Homer City litigation, refer to the 
preamble of the CSAPR Update.\41\
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    \40\ On August 21, 2012, the D.C. Circuit issued a decision in 
EME Homer City Generation, L.P. v. EPA, 696 F.3d 7 (D.C. Cir. 2012), 
vacating CSAPR. The EPA sought review with the D.C. Circuit en banc 
and the D.C. Circuit declined to consider EPA's appeal en banc. EME 
Homer City Generation, L.P. v. EPA, No. 11-1302 (D.C. Cir. January 
24, 2013), ECF No. 1417012 (denying EPA's motion for rehearing en 
banc).
    \41\ Cross-State Air Pollution Rule Update for the 2008 Ozone 
NAAQS, 81 FR 74504, 74511 (October 26, 2016).
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    In 2016, the EPA promulgated the CSAPR Update to address interstate 
transport of ozone pollution with respect to the 2008 ozone NAAQS.\42\ 
The final rule updated the CSAPR ozone season NOX emissions 
budgets for 22 states to achieve cost-effective and immediately 
feasible NOX emissions reductions from EGUs within those 
states.\43\ The EPA aligned the analysis and implementation of the 
CSAPR Update with the 2017 ozone season in order to assist downwind 
states with timely attainment of the 2008 ozone NAAQS.\44\ The CSAPR 
Update implemented the budgets through FIPs requiring sources to 
participate in a revised CSAPR NOX ozone season trading 
program beginning with the 2017 ozone season. As under CSAPR, each 
state could submit a good neighbor SIP at any time that, if approved by 
the EPA, would replace the CSAPR Update FIP for that state. The final 
CSAPR Update also addressed the remand by the D.C. Circuit of certain 
states' CSAPR phase 2 ozone season NOX emissions budgets in 
EME Homer City II.
---------------------------------------------------------------------------

    \42\ 81 FR 74504.
    \43\ One state, Kansas, was made newly subject to ozone season 
NOX requirements by the CSAPR Update. All other CSAPR 
Update states were already subject to ozone season NOX 
requirements under CSAPR.
    \44\ 81 FR 74516. EPA's final 2008 Ozone NAAQS SIP Requirements 
Rule, 80 FR 12264, 12268 (March 6, 2015), revised the attainment 
deadline for ozone nonattainment areas designated as Moderate to 
July 20, 2018. See 40 CFR 51.1103. In order to demonstrate 
attainment by this deadline, states were required to rely on design 
values calculated using ozone season data from 2015 through 2017, 
since the July 20, 2018, deadline did not afford enough time for 
measured data of the full 2018 ozone season.
---------------------------------------------------------------------------

    In December 2018, the EPA promulgated the CSAPR ``Close-Out,'' 
which determined that no further enforceable reductions in emissions of 
NOX were required with respect to the

[[Page 20052]]

2008 ozone NAAQS for 20 of the 22 eastern states covered by the CSAPR 
Update, and reflected that determination in revisions to the existing 
state-specific sections of the CSAPR Update regulations for those 
states.\45\
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    \45\ Determination Regarding Good Neighbor Obligations for the 
2008 Ozone National Ambient Air Quality Standard, 83 FR 65878, 65882 
(Dec. 21, 2018). After promulgating the CSAPR Update and before 
promulgating the CSAPR Close-Out, the EPA approved a SIP from 
Kentucky resolving the Commonwealth's good neighbor obligations for 
the 2008 ozone NAAQS. 83 FR 33730 (July 17, 2018). In the Revised 
CSAPR Update, the EPA made an error correction under CAA section 
110(k)(6) to convert this approval to a disapproval, because the 
Kentucky approval relied on the same analysis which the D.C. Circuit 
determined to be unlawful in the CSAPR Close-Out.
---------------------------------------------------------------------------

    The CSAPR Update and the CSAPR Close-Out were both subject to legal 
challenges in the D.C. Circuit. Wisconsin v. EPA, 938 F.3d 303 (D.C. 
Cir. 2019) (Wisconsin); New York v. EPA, 781 Fed. App'x 4 (D.C. Cir. 
2019) (New York). In September 2019, the D.C. Circuit upheld the CSAPR 
Update in virtually all respects but remanded the rule because it was 
partial in nature and did not fully eliminate upwind states' 
significant contribution to nonattainment or interference with 
maintenance of the 2008 ozone NAAQS by ``the relevant downwind 
attainment deadlines'' in the CAA. Wisconsin, 938 F.3d at 313-15. In 
October 2019, the D.C. Circuit vacated the CSAPR Close-Out on the same 
grounds that it remanded the CSAPR Update in Wisconsin, specifically 
that the Close-Out rule did not address good neighbor obligations by 
``the next applicable attainment date'' of downwind states. New York, 
781 Fed. App'x at 7.\46\
---------------------------------------------------------------------------

    \46\ Subsequently, the D.C. Circuit made clear in a decision 
reviewing EPA's denial of a petition under CAA section 126 that the 
holding in Wisconsin regarding alignment with downwind area's 
attainment schedules applies with equal force to the Marginal area 
attainment date established under CAA section 181(a). See Maryland 
v. EPA, 958 F.3d 1185, 1203-04 (D.C. Cir. 2020).
---------------------------------------------------------------------------

    In response to the Wisconsin remand of the CSAPR Update and the New 
York vacatur of the CSAPR Close-Out, the EPA promulgated the Revised 
CSAPR Update on April 30, 2021.\47\ The Revised CSAPR Update found that 
the CSAPR Update was a full remedy for nine of the covered states. For 
the 12 remaining states, the EPA found that their projected 2021 ozone 
season NOX emissions significantly contribute to downwind 
states' nonattainment or maintenance problems. The EPA issued new or 
amended FIPs for these 12 states and required implementation of revised 
emissions budgets for EGUs beginning with the 2021 ozone season. Based 
on EPA's assessment of remaining air quality issues and additional 
emissions control strategies for EGUs and emissions sources in other 
industry sectors (non-EGUs), the EPA determined that the NOX 
emissions reductions achieved by the Revised CSAPR Update fully 
eliminated these states' significant contributions to downwind air 
quality problems for the 2008 ozone NAAQS. As under the CSAPR and the 
CSAPR Update, each state can submit a good neighbor SIP at any time 
that, if approved by EPA, would replace the Revised CSAPR Update FIP 
for that state.\48\
---------------------------------------------------------------------------

    \47\ Revised Cross-State Air Pollution Rule Update for the 2008 
Ozone NAAQS, 86 FR 23054 (April 30, 2021).
    \48\ The Revised CSAPR Update is currently subject to a petition 
for judicial review pending in the D.C. Circuit Court of Appeals, 
Midwest Ozone Group v. EPA, No. 21-1146 (D.C. Cir. June 25, 2021).
---------------------------------------------------------------------------

IV. Air Quality Issues Addressed and Overall Approach for the Proposed 
Rule

A. The Interstate Ozone Transport Air Quality Challenge

1. Nature of Ozone and the Ozone NAAQS
    Ground-level ozone is not emitted directly into the air but is 
created by chemical reactions between NOX and volatile 
organic compounds (VOCs) in the presence of sunlight. Emissions from 
electric utilities and industrial facilities, motor vehicles, gasoline 
vapors, and chemical solvents are some of the major sources of 
NOX and VOCs.
    Because ground-level ozone formation increases with temperature and 
sunlight, ozone levels are generally higher during the summer months. 
Increased temperature also increases emissions of volatile man-made and 
biogenic organics and can also indirectly increase NOX 
emissions (e.g., increased electricity generation for air 
conditioning).
    On October 1, 2015, the EPA strengthened the primary and secondary 
ozone standards to 70 ppb as an 8-hour level.\49\ Specifically, the 
standards require that the 3-year average of the fourth highest 24-hour 
maximum 8-hour average ozone concentration may not exceed 70 ppb as a 
truncated value (i.e., digits to right of decimal removed).\50\ In 
general, areas that exceed the ozone standard are designated as 
nonattainment areas, pursuant to the designations process under CAA 
section 107, and are subject to heightened planning requirements 
depending on the degree of severity of their nonattainment 
classification, see CAA sections 181, 182.
---------------------------------------------------------------------------

    \49\ 80 FR 65291.
    \50\ 40 CFR part 50, Appendix P to part 50
---------------------------------------------------------------------------

    In the process of setting the 2015 ozone NAAQS, the EPA noted that 
the conditions conducive to the formation of ozone (i.e., seasonally-
dependent factors such as ambient temperature, strength of solar 
insolation, and length of day) differ by location, and that the Agency 
believes it is important that ozone monitors operate during all periods 
when there is a reasonable possibility of ambient levels approaching 
the level of the NAAQS. At that time, the EPA stated that ambient ozone 
concentrations in many areas could approach or exceed the level of the 
NAAQS, more frequently and during more months of the year compared with 
the historical ozone season monitoring lengths. Consequently, the EPA 
extended the ozone monitoring season for many locations. See 80 FR 
65416 for more details.
    Furthermore, the EPA stated that in addition to being affected by 
changing emissions, future ozone concentrations may also be affected by 
climate change. Modeling studies in the EPA's Interim Assessment (U.S. 
EPA, 2009a) that are cited in support of the 2009 Endangerment Finding 
under CAA section 202(a) (74 FR 66496, Dec. 15, 2009) as well as a 
recent assessment of potential climate change impacts (Fann et al., 
2015) project that climate change may lead to future increases in 
summer ozone concentrations across the contiguous U.S.\51\ (80 FR 
65300). The increase in ozone results from changes in local weather 
conditions, including temperature and atmospheric circulation patterns, 
as well as changes in ozone precursor emissions that are influenced by 
meteorology (Nolte et al., 2018). While the projected impact may not be 
uniform, climate change has the potential to increase average 
summertime ozone relative to a future without climate 
change.52 53 54 Climate

[[Page 20053]]

change has the potential to offset some of the improvements in ozone 
air quality, and therefore some of the improvements in public health, 
that are expected from reductions in emissions of ozone precursors (80 
FR 65300).
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    \51\ These modeling studies are based on coupled global climate 
and regional air quality models and are designed to assess the 
sensitivity of U.S. air quality to climate change. A wide range of 
future climate scenarios and future years have been modeled and 
there can be variations in the expected response in U.S. O\3\ by 
scenario and across models and years, within the overall signal of 
higher summer O\3\ concentrations in a warmer climate.
    \52\ Fann NL, Nolte CG, Sarofim MC, Martinich J, Nassikas NJ. 
Associations Between Simulated Future Changes in Climate, Air 
Quality, and Human Health. JAMA Netw Open. 2021;4(1):e2032064. doi: 
10.1001/jamanetworkopen.2020.32064.
    \53\ Christopher G Nolte, Tanya L Spero, Jared H Bowden, Marcus 
C Sarofim, Jeremy Martinich, Megan S Mallard. Regional temperature-
ozone relationships across the U.S. under multiple climate and 
emissions scenarios. J Air Waste Manag Assoc. 2021 Oct;71(10):1251-
1264. doi: 10.1080/10962247.2021.1970048.
    \54\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, 
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air 
Quality. In Impacts, Risks, and Adaptation in the United States: 
Fourth National Climate Assessment, Volume II [Reidmiller, D.R., 
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/
NCA4.2018.CH13.
---------------------------------------------------------------------------

2. Ozone Transport
    Studies have established that ozone formation, atmospheric 
residence, and transport occur on a regional scale (i.e., thousands of 
kilometers) over much of the U.S.\55\ While substantial progress has 
been made in reducing ozone in many areas, the interstate transport of 
ozone precursor emissions remains an important contributor to peak 
ozone concentrations and high-ozone days during the summer ozone 
season.
---------------------------------------------------------------------------

    \55\ Bergin, M.S. et al. (2007) Regional air quality: Local and 
interstate impacts of NOX and SO2 emissions on 
ozone and fine particulate matter in the eastern United States. 
Environmental Sci & Tech. 41: 4677-4689.
---------------------------------------------------------------------------

    The EPA has previously concluded in the NOX SIP Call, 
CAIR, CSAPR, the CSAPR Update, and the Revised CSAPR Update that a 
regional NOX control strategy would be effective in reducing 
regional-scale transport of ozone precursor emissions. NOX 
emissions can be transported downwind as NOX or as ozone 
after transformation in the atmosphere. In any given location, ozone 
pollution levels are impacted by a combination of background ozone 
concentration, local emissions, and emissions from upwind sources 
resulting from ozone transport. Downwind states' ability to meet 
health-based air quality standards such as the NAAQS is challenged by 
the transport of ozone pollution across state borders. For example, 
ozone assessments conducted for the October 2015 Regulatory Impact 
Analysis of the Final Revisions to the National Ambient Air Quality 
Standards for Ground-Level Ozone continue to show the importance of 
NOX emissions for ozone transport. This analysis is included 
in the docket for this proposal.
    Further, studies have found that EGU NOX emissions 
reductions can be effective in reducing individual 8-hour peak ozone 
concentrations and in reducing 8-hour peak ozone concentrations 
averaged across the ozone season. For example, a study that evaluates 
the effectiveness on ozone concentrations of EGU NOX 
reductions achieved under the NOX Budget Trading Program 
(i.e., the NOX SIP Call) shows that regulating 
NOX emissions in that program was highly effective in 
reducing ozone concentrations during the ozone season.\56\
---------------------------------------------------------------------------

    \56\ Butler, et al., ``Response of Ozone and Nitrate to 
Stationary Source Reductions in the Eastern USA''. Atmospheric 
Environment, 2011.
---------------------------------------------------------------------------

    Previous regional ozone transport efforts, including the 
NOX SIP Call, CAIR, CSAPR, the CSAPR Update, and the Revised 
CSAPR Update, required ozone season NOX reductions from EGU 
sources to address interstate transport of ozone. Together with 
NOX, EPA has also identified VOCs as a precursor in forming 
ground-level ozone. Ozone formation chemistry can be ``NOX-
limited,'' where ozone production is primarily determined by the amount 
of NOX emissions or ``VOC-limited,'' where ozone production 
is primarily determined by the amount of VOC emissions.\57\ The EPA and 
others have long regarded NOX to be the more significant 
ozone precursor in the context of interstate ozone transport.\58\
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    \57\ ``Ozone Air Pollution.'' Introduction to Atmospheric 
Chemistry, by DANIEL J. JACOB, Princeton University Press, 
PRINCETON, NEW JERSEY, 1999, pp. 231-244.
    \58\ 81 FR 74514.
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    The EPA has determined that the regulation of VOCs as an ozone 
precursor is not necessary to eliminate significant contribution of 
ozone transport to downwind areas in this proposed rule. As described 
in Section VI.A of this proposed rule, the EPA examined the results of 
the contribution modeling performed for this rule to identify the 
portion of the ozone contribution attributable to anthropogenic 
NOX emissions versus VOC emissions from each linked upwind 
state to each downwind receptor. Our analysis of the ozone contribution 
from upwind states subject to regulation under this proposed rule 
demonstrates that the vast majority of the downwind air quality areas 
are NOX-limited, rather than VOC-limited. Therefore, the 
proposed rule's strategy for reducing regional-scale transport of ozone 
targets NOX emissions from stationary sources to achieve the 
most effective reductions of ozone transport over the geography of the 
affected downwind areas.
    Commenters on prior ozone transport rules have asserted that VOC 
emissions harm underserved and overburdened communities experiencing 
disproportionate environmental health burdens and facing other 
environmental injustices. The EPA acknowledges that VOCs can contain 
toxic chemicals that are detrimental to public health. The EPA 
conducted a demographic analysis as part of the regulatory impact 
analysis for the 2015 revisions to the primary and secondary ozone 
NAAQS. This analysis, which is included in the docket for this proposed 
rulemaking, found greater representation of minority populations in 
areas with poor air quality relative to the revised ozone standard than 
in the U.S. as a whole. The EPA concluded that populations in these 
areas would be expected to benefit from implementation of future air 
pollution control actions from state and local air agencies in 
implementing the strengthened standard. This proposed rule is an 
example of air pollution control actions implemented by the federal 
government in support of the more stringent 2015 ozone NAAQS, and 
populations living in downwind ozone nonattainment areas are expected 
to benefit from improved air quality that will result from reducing 
ozone transport. Further discussion of the environmental justice 
impacts of this proposed rule is located in Section VIII of this 
proposed rule and in the accompanying regulatory impact analysis, 
titled ``Regulatory Impact Analysis for the Proposed Federal 
Implementation Plan Addressing Regional Ozone Transport for the 2015 
Ozone National Ambient Air Quality Standard'' [EPA-452/D-22-001], which 
is available in the docket for this rulemaking.
    The Agency regulates exposure to toxic pollutant concentrations and 
ambient exposure to criteria pollutants other than ozone through other 
sections of the Act, such as the regulation of hazardous air pollutants 
under CAA section 112 or the process for revising and implementing the 
NAAQS under CAA sections 107-110. The purpose of the proposed 
rulemaking is to protect public health and the environment by 
eliminating significant contribution from 26 states to nonattainment or 
maintenance of the 2015 ozone NAAQS in order to meet the requirements 
of the CAA's interstate transport provision. In this proposed rule, the 
EPA continues to observe that requiring NOX emissions 
reductions from stationary sources is an effective strategy for 
reducing regional ozone transport in the U.S.
    In Section VI of this proposed rule, EPA describes the multi-factor 
test that is used to determine NOX emissions reductions that 
are cost-effective and reduce interstate transport of ground-level 
ozone. Our analysis indicates that the EGU and non-EGU control 
requirements proposed in this rule will provide meaningful improvements 
in air quality at the downwind receptors. Based on the implementation 
schedule

[[Page 20054]]

established in Section VII.A of this proposed rule, the EPA proposes to 
determine that the regulatory requirements included in the proposed 
rule are as expeditious as practicable and are aligned with the 
attainment schedule of downwind areas.
3. Health and Environmental Effects
    Exposure to ambient ozone causes a variety of negative effects on 
human health, vegetation, and ecosystems. In humans, acute and chronic 
exposure to ozone is associated with premature mortality and a number 
of morbidity effects, such as asthma exacerbation. In ecosystems, ozone 
exposure causes visible foliar injury, decreases plant growth, and 
affects ecosystem community composition. See EPA's October 2015 
Regulatory Impact Analysis of the Final Revisions to the National 
Ambient Air Quality Standards for Ground-Level Ozone \59\ in the docket 
for this proposal for more information on the human health and 
ecosystem effects associated with ambient ozone exposure.
---------------------------------------------------------------------------

    \59\ Available at https://www.epa.gov/sites/default/files/2016-02/documents/20151001ria.pdf.
---------------------------------------------------------------------------

B. Proposed Rule Approach

1. The 4-Step Interstate Transport Framework
    The EPA first developed a multi-step process to address the 
requirements of the good neighbor provision in the NOX SIP 
Call and CAIR. The Agency built upon this framework and further refined 
the methodology for addressing interstate transport obligations in 
subsequent rules such as CSAPR, the CSAPR Update, and the Revised CSAPR 
Update.\60\ In CSAPR, the EPA first articulated a ``4-step framework'' 
within which to assess interstate transport obligations for ozone. In 
this proposed action to address interstate transport obligations for 
the 2015 ozone NAAQS, the EPA is again utilizing the 4-step interstate 
transport framework. These steps are: (1) Identifying downwind 
receptors that are expected to have problems attaining the NAAQS 
(nonattainment receptors) or maintaining the NAAQS (maintenance 
receptors); (2) determining which upwind states are ``linked'' to these 
identified downwind receptors based on a numerical contribution 
threshold; (3) for states linked to downwind air quality problems, 
identifying upwind emissions on a statewide basis that significantly 
contribute to downwind nonattainment or interfere with downwind 
maintenance of the NAAQS, considering cost- and air quality-based 
factors; and (4) for upwind states that are found to have emissions 
that significantly contribute to nonattainment or interfere with 
maintenance of the NAAQS in any downwind state, implementing the 
necessary emissions reductions through enforceable measures.
---------------------------------------------------------------------------

    \60\ See CSAPR, Final Rule, 76 FR 48208, 48248-48249 (August 8, 
2011); CSAPR Update, Final Rule, 81 FR 74504, 74517-74521 (October 
26, 2016).
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a. Step 1 Approach
    The EPA proposes to continue to apply the method of the CSAPR 
Update and the Revised CSAPR Update for identifying nonattainment and 
maintenance receptors. In the Revised CSAPR Update, the EPA assessed 
downwind air quality problems using modeled future air quality 
concentrations for an analytic year aligned with the relevant 
attainment deadline for the NAAQS under consideration in that 
rulemaking.\61\ Similarly, in CSAPR, downwind air quality problems were 
assessed using modeled future air quality concentrations for a year 
aligned with attainment deadlines for the NAAQS considered in that 
rulemaking. The base case scenario provides an assessment of future air 
quality conditions that generally accounts for enforceable ``on-the-
books'' emissions reductions and provides the most up-to-date forecast 
of what future emissions would resemble, in the absence of the 
transport policy in the proposed rule under evaluation. Downwind air 
quality problems are identified as the locations of monitoring sites 
that are projected to be unable to attain the NAAQS (``nonattainment 
receptors'') or as the locations of monitoring sites that are projected 
to be unable to maintain the NAAQS (``maintenance receptors''). In the 
CSAPR Update and the Revised CSAPR Update, unlike CSAPR,\62\ the EPA 
also considered currently available monitored air quality data to 
further inform the identification of projected downwind air quality 
problems. These same considerations are included for this proposal. 
Further details regarding the application of Step 1 of the 4-step 
interstate transport framework in this proposal are described in 
Section V.D of this proposed rule.
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    \61\ Specifically, the EPA analyzed 2021 to align with the 
attainment date for areas classified as Severe nonattainment for the 
2008 ozone NAAQS, and because the last full ozone season before that 
date, in 2020, was already in the past.
    \62\ In CSAPR, the EPA did not use current monitored air quality 
conditions, because that data was influenced by the invalidated CAIR 
rule, which the EPA was replacing with CSAPR. See 81 FR 74506, 
74531. As the EPA is not replacing an existing transport program in 
this proposed rule, the Agency proposes to once again consider 
current monitored data as part of the process for identifying 
projected receptors for this rulemaking.
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b. Step 2 Approach
    The EPA proposes to apply the same approach for identifying which 
states are contributing to downwind nonattainment and maintenance 
receptors as it has applied in the three prior CSAPR rulemakings. 
CSAPR, the CSAPR Update, and the Revised CSAPR Update used a screening 
threshold of 1 percent of the NAAQS to identify upwind states that were 
``linked'' to downwind air pollution problems. States with 
contributions greater than or equal to the threshold for at least one 
downwind nonattainment or maintenance receptor identified in Step 1 
were identified as needing further evaluation of their good neighbor 
obligations to downwind states.\63\ The EPA evaluated each state's 
contribution based on the average relative downwind impact calculated 
over multiple days.\64\ States whose air quality impacts to all 
downwind receptors were below this threshold did not require further 
evaluation for actions to address transport. In other words, the EPA 
determined that these states did not contribute to downwind air quality 
problems and therefore had no emissions reduction obligations under the 
good neighbor provision. The EPA applies a contribution screening 
threshold because many downwind ozone nonattainment areas receive 
transport contributions from a number of upwind states. While the 
proportion of contribution from a single upwind state may be relatively 
small, the effect of collective contribution resulting from multiple 
upwind states may substantially contribute to nonattainment of or 
interference with maintenance of the NAAQS in downwind areas. The 
preambles to the

[[Page 20055]]

proposed and final CSAPR rules discuss the use of the 1 percent 
threshold for CSAPR. See 75 FR 45237 (August 2, 2010); 76 FR 48238 
(August 8, 2011). The same metric is discussed in the CSAPR Update, see 
81 FR 74538, and in the Revised CSAPR Update, see 86 FR 23054. In this 
proposed rule, the EPA updated the air quality modeling data used for 
determining contributions at Step 2 of the four-step interstate 
transport framework. The EPA otherwise continues to find that this 
threshold is appropriate to continue to apply for the 2015 ozone NAAQS. 
This proposal's application of the Step 2 approach is comprehensively 
described in Section V of this proposed rule.
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    \63\ For ozone, the impacts include those from VOC and 
NOX from all sectors.
    \64\ The number of days used in calculating the average 
contribution metric has historically been determined in a manner 
that is generally consistent with EPA's recommendations for 
projecting future year ozone design values. Our ozone attainment 
demonstration modeling guidance at the time of CSAPR recommended 
using all model-predicted days above the NAAQS to calculate future 
year design values (https://www3.epa.gov/ttn/scram/guidance/guide/final-03-pm-rh-guidance.pdf). In 2014, the EPA issued draft revised 
guidance that changed the recommended number of days to the top-10 
model predicted days (https://www3.epa.gov/ttn/scram/guidance/guide/Draft-O3-PM-RH-Modeling_Guidance-2014.pdf). For the CSAPR Update, 
the EPA transitioned to calculating design values based on this 
draft revised approach. The revised modeling guidance was finalized 
in 2019 and, in this regard, EPA is calculating both the ozone 
design values and the contributions based on a top-10 day approach 
(https://www3.epa.gov/ttn/scram/guidance/guide/O3-PM-RH-Modeling_Guidance-2018.pdf).
---------------------------------------------------------------------------

c. Step 3 Approach
    The EPA proposes to continue to apply the same approach as the 
prior three CSAPR rulemakings for evaluating ``significant 
contribution'' at Step 3.\65\ For states that are linked in Step 3 to 
downwind air quality problems, CSAPR, the CSAPR Update, and the Revised 
CSAPR Update evaluated NOX reduction potential, cost, and 
downwind air quality improvements available at various mitigation 
technology breakpoints (represented by cost thresholds) in the multi-
factor test. In CSAPR, the CSAPR Update, and the Revised CSAPR Update, 
the EPA selected the technology breakpoint (represented by a cost 
threshold) that, in general, maximized cost-effectiveness--i.e., that 
achieved a reasonable balance of incremental NOX reduction 
potential and corresponding downwind ozone air quality improvements, 
relative to the other emissions budget levels evaluated. See, e.g., 81 
FR 74550. The EPA determined the level of emissions reductions 
associated with that level of control stringency to constitute 
significant contribution to nonattainment or interfere with maintenance 
of a NAAQS downwind. See, e.g., 86 FR 23116. This approach was upheld 
by the U.S. Supreme Court in EPA v. EME Homer City.\66\
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    \65\ For simplicity, the EPA (and courts) at times will refer to 
the Step 3 analysis as determining ``significant contribution''; 
however, EPA's approach at Step 3 also implements the ``interference 
with maintenance'' prong of the good neighbor provision, by also 
addressing emissions that impact the maintenance receptors 
identified at Step 1. See 86 FR 23074 (``In effect, EPA's 
determination of what level of upwind contribution constitutes 
`interference' with a maintenance receptor is the same determination 
as what constitutes `significant contribution' for a nonattainment 
receptor. Nonetheless, this continues to give independent effect to 
prong 2 because the EPA applies a broader definition for identifying 
maintenance receptors, which accounts for the possibility of 
problems maintaining the NAAQS under realistic potential future 
conditions.'').
    \66\ EPA v. EME Homer City Generation, L.P., 572 U.S. 489 
(2014).
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    The EPA proposes in this action to apply this approach to identify 
EGU and non-EGU NOX control stringencies necessary to 
address significant contribution for the 2015 ozone NAAQS. The EPA 
applies a multifactor assessment using cost-thresholds, total emissions 
reduction potential, and downwind air quality effects as key factors in 
determining a reasonable balance of NOX controls in light of 
the downwind air quality problems. EPA's evaluation of available 
NOX mitigation strategies for EGUs focuses on the same core 
set of measures as prior transport rules, and the EPA proposes a 
control stringency for EGUs from these measures that is commensurate 
with the nature of the ongoing ozone nonattainment and maintenance 
problems observed for the 2015 ozone NAAQS. Similarly, in this action, 
the EPA includes other industrial sources (non-EGUs) in its Step 3 
analysis and proposes emissions limitations for certain non-EGU sources 
as needed to eliminate significant contribution and interference with 
maintenance. The available reductions and cost-levels for the non-EGU 
stringency is generally commensurate with the control strategy for 
EGUs.
    In CSAPR, the CSAPR Update, and the Revised CSAPR Update, EPA 
focused its Step 3 analysis on EGUs. In the Revised CSAPR Update, in 
response to the Wisconsin decision's finding that the EPA had not 
adequately evaluated potential non-EGU reductions, see 938 F.3d at 318, 
the EPA determined that the available NOX emissions 
reductions from non-EGU sources, for purposes of addressing good 
neighbor obligations for the 2008 ozone NAAQS, at a comparable cost 
threshold to the required EGU emissions reductions (for which EPA used 
an adjusted representative cost of $1,800 per ton), and based on the 
timing of when such measures could be implemented, did not provide a 
sufficiently meaningful and timely air quality improvement at the 
downwind receptors before those receptors were projected to resolve. 
See 86 FR 23110. On that basis, the EPA made a finding that emissions 
reductions from non-EGU sources were not required to eliminate 
significant contribution to downwind air quality problems under the 
interstate transport provision for the 2008 ozone NAAQS. In this 
proposal, EPA's ``significant contribution'' analysis at Step 3 of the 
4-step framework includes a comprehensive evaluation of major 
stationary source non-EGU industries in the linked upwind states. The 
EPA is proposing to find that emissions from certain non-EGU sources in 
the upwind states significantly contribute to downwind air quality 
problems for the 2015 ozone NAAQS, and that cost-effective emissions 
reductions from these sources are required to eliminate significant 
contribution under the interstate transport provision. Therefore, this 
proposed rule includes required emissions reductions from non-EGU 
sources in upwind states to fulfill interstate transport obligations 
for the 2015 ozone NAAQS. This analysis is described fully in Section 
VI of the proposed rule.
    In this proposed rule, the EPA also continues to apply its approach 
for assessing and avoiding ``over-control.'' In EME Homer City, the 
Supreme Court held that ``EPA cannot require a State to reduce its 
output of pollution by more than is necessary to achieve attainment in 
every downwind State or at odds with the one-percent threshold the 
Agency has set.'' 572 U.S. at 521. The Court acknowledged that 
``instances of `over-control' in particular downwind locations may be 
incidental to reductions necessary to ensure attainment elsewhere.'' 
Id. at 492.

    ``Because individual upwind States often `contribute 
significantly' to nonattainment in multiple downwind locations, the 
emissions reductions required to bring one linked downwind State 
into attainment may well be large enough to push other linked 
downwind States over the attainment line. As the Good Neighbor 
Provision seeks attainment in every downwind State, however, 
exceeding attainment in one State cannot rank as `over-control' 
unless unnecessary to achieving attainment in any downwind State. 
Only reductions unnecessary to downwind attainment anywhere fall 
outside the Agency's statutory authority.''

Id. at 522 (footnotes excluded).
    The Court further explained that ``while EPA has a statutory duty 
to avoid over-control, the Agency also has a statutory obligation to 
avoid `under-control,' i.e., to maximize achievement of attainment 
downwind.'' Id. at 523. Therefore, in the CSAPR Update and Revised 
CSAPR Update, the EPA evaluated possible over-control by considering 
whether an upwind state is linked solely to downwind air quality 
problems that can be resolved at a lower cost threshold, or if upwind 
states would reduce their emissions at a lower cost threshold to the 
extent that they would no longer meet or exceed the 1 percent air 
quality contribution threshold. See, e.g., 81 FR at 74551-52. See also 
Wisconsin, 938 F.3d at 325

[[Page 20056]]

(over-control must be proven through a `` `particularized, as-applied 
challenge' '') (quoting EME Homer City Generation, 572 U.S. at 523-24). 
The EPA continues to apply this framework for assessing over-control in 
this proposed rule, and, as discussed in Section VI.D.4 of this 
proposed rule, does not find any over-control at the proposed 
stringency to be sufficiently certain to warrant a relaxation in 
requirements for the sources in any covered state.
    This evaluation of cost, NOX reductions, and air quality 
improvements, including consideration of whether there is proven over-
control, results in EPA's determination of the appropriate level of 
upwind control stringency that would result in elimination of emissions 
that significantly contribute to nonattainment or interfere with 
maintenance of the NAAQS in downwind areas.
d. Step 4 Approach
    The EPA proposes an approach similar to its prior transport 
rulemakings to implement the necessary emissions reductions through 
permanent and enforceable measures. The EPA proposes to require EGU 
sources to participate in an emissions trading program and proposes 
additional enhancements to the trading regime to maintain the selected 
control stringency over time and improve emissions performance at 
individual units, offering a necessary measure of assurance that 
emissions controls will be operated throughout the ozone season. For 
non-EGUs, the EPA proposes permanent and enforceable emissions rate 
limits and work practice standards, and associated compliance 
requirements, on several types of NOX-emitting combustion 
units across several industrial sectors. The measures for both EGUs and 
non-EGUs are proposed to be required throughout the May 1-September 30 
ozone season annually. The EGU program will begin with the 2023 ozone 
season, and non-EGU implementation will begin with the 2026 ozone 
season. Refer to Section VII.A of this proposed rule for details on the 
implementation schedule.
    Based on the EPA's experience in implementing prior transport 
rulemakings, the Agency is proposing several enhancements to its 
trading-program approach for implementing good neighbor requirements 
for EGUs. In CSAPR, the CSAPR Update, and the Revised CSAPR Update, the 
EPA established interstate trading programs for EGUs to implement the 
necessary emissions reductions. In each of these rules, EGUs in each 
covered state are assigned an emissions budget for their collective 
emissions. Emissions allowances are allocated to units covered by the 
trading program, and the covered units then surrender allowances after 
the close of each control period, usually in an amount equal to their 
ozone season EGU NOX emissions. While these programs have 
been effective in achieving overall reductions in emissions, experience 
has shown that these programs may not fully reflect in perpetuity the 
degree of emissions stringency determined necessary to eliminate 
significant contribution in Step 3 and may not adequately ensure the 
control of emissions throughout all days of the ozone season. At the 
same time, the EPA continues to find that an interstate-trading program 
approach delivers substantial benefits at Step 4 in terms of affording 
an appropriate degree of compliance flexibility, certainty in emissions 
outcomes, data and performance transparency, and cost-effective 
achievement of a high degree of aggregate emissions reductions. As 
such, EPA proposes to retain an interstate trading program approach 
while proposing several enhancements to that approach.
    Thus, in this rulemaking, the EPA is proposing to include budget-
setting procedures in the regulations that will allow state emissions 
budgets for control periods in 2025 and later years to reflect more 
current data on the composition and utilization of the EGU fleet (e.g., 
the 2025 budgets would reflect 2023 data, the 2026 budgets would 
reflect 2024 data, etc.). These enhancements would enable the trading 
program to better maintain over time the selected control stringency 
that was determined to be necessary to address states' good neighbor 
obligations with respect to the 2015 ozone NAAQS. In prior programs, 
where state emissions budgets were static across years rather than 
calibrated to yearly fleet changes, the EPA has observed instances of 
units idling their emission controls in the latter years of the 
program.
    In the trading programs established for ozone season NOX 
emissions under CSAPR, the CSAPR Update, and the Revised CSAPR Update, 
the EPA included assurance provisions to limit state emissions to 
levels below 121 percent of the state's budget by requiring additional 
allowance surrenders in the instance that emissions in the state exceed 
this level. This limit on the degree to which a state's emissions can 
exceed its budget is designed to allow for a certain level of year-to-
year variability within power sector emissions to account for 
fluctuations in demand and EGU operations and is responsive to previous 
court decisions (see discussion in Section VII.B.4 of this proposed 
rule). In this action, the EPA again proposes to retain the existing 
assurance provisions that limit state emissions to levels below 121 
percent of the state's budget by requiring additional allowance 
surrenders in the instance that emissions in the state exceed this 
level for the 2023 and 2024 control periods. For control periods in 
2025 and later years, the EPA is proposing to maintain the same general 
approach, but with adjustments that account for actual operational 
conditions in each control period to determine the specific levels 
above which additional allowance surrenders would be required. In 
addition, EPA is also proposing several additional enhancements to the 
EGU trading program in this action, including routine recalibrations of 
the total amount of banked allowances, unit-specific backstop daily 
emissions rates for certain units, and unit-specific secondary 
emissions limitations for units that contribute to exceedances of the 
assurance levels, to ensure EGU emissions control operation and 
associated air quality improvements. Implementation of the proposed EGU 
emissions reductions using a CSAPR NOX trading program is 
further described in Section VII.B of this proposed rule.
    In this action, the EPA is also proposing to establish emissions 
limitations for the non-EGU industry sources listed in Table III.A-1. 
The EPA has the authority to require emissions limitations from 
stationary sources, as well as from other sources and emissions 
activities, under CAA section 110(a)(2)(D)(i)(I). The EPA proposes that 
requiring NOX emissions reductions through emissions rate 
limits from certain non-EGU industry sources that the EPA found at Step 
3 to be relatively impactful \67\ on downwind air quality is an 
effective strategy for reducing regional ozone transport. Therefore, 
the EPA proposes NOX emissions limitations and associated 
compliance requirements for non-EGU sources to ensure the elimination 
of significant contribution of ozone precursor emissions required under 
the interstate

[[Page 20057]]

transport provision for the 2015 ozone NAAQS.
---------------------------------------------------------------------------

    \67\ Section III of the Non-EGU Screening Assessment memorandum 
in the docket for this rulemaking describes EPA's approach to 
evaluating impacts on downwind air quality, considering estimated 
total, maximum, and average contributions from each industry and the 
total number of receptors with contributions from each industry.
---------------------------------------------------------------------------

    Finally, the EPA proposes that the control measures determined to 
be required for the identified EGU and non-EGU sources apply to both 
existing units and any new, modified, or reconstructed units meeting 
the applicability criteria established in this proposal. This is 
consistent with EPA's transport actions dating back to the 
NOX SIP Call and the NOX Budget Trading Program. 
In all CSAPR EGU trading programs, for instance, new EGUs are subject 
to the program, and the EPA established provisions for the allocation 
of allowances to such units through ``new unit set asides.'' See, e.g., 
86 FR 23126. In the NOX SIP Call, the EPA required that 
states cover new and existing units in the relevant source sectors 
through an enforceable cap or other emissions limitation. See 40 CFR 
51.121(f). EPA's approach of including new units in the NOX 
Budget Trading Program promulgated under EPA's CAA section 126 
authority was upheld by the D.C. Circuit in Appalachian Power v. EPA, 
249 F.3d 1032 (2001). The EPA explained in its action:

    Once EPA has determined that the emissions from the existing 
sources in an upwind State already make a significant contribution 
to one or more petitioning downwind States, any additional emissions 
from a new source in that upwind State would also constitute a 
portion of that significant contribution, unless the emissions from 
that new source are limited to the level of highly effective 
controls.

Id. at 1058 (quoting EPA 1999 RTC at 39). The court affirmed this 
approach: ``Indeed, it would be irrational to enable the EPA to make 
findings that a group of sources in an upwind state contribute to 
downwind nonattainment, but then preclude the EPA from regulating new 
sources that contribute to that same pollution.'' Id. at 1057-58. The 
EPA proposes to adopt the same approach in this action, because this 
reasoning is equally applicable to addressing interstate transport 
obligations under CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone 
NAAQS.
2. FIP Authority for Each State Covered by the Proposed Rule
    On October 1, 2015, the EPA promulgated a revision to the 2015 8-
hour ozone NAAQS, lowering the level of both the primary and secondary 
standards to 0.070 parts per million (ppm).\68\ These revisions of the 
NAAQS, in turn, established a 3-year deadline for states to provide SIP 
submissions addressing infrastructure requirements under CAA sections 
110(a)(1) and 110(a)(2), including the good neighbor provision, by 
October 1, 2018. If the EPA makes a determination that a state failed 
to submit a SIP, or if EPA disapproves a SIP submission, then the EPA 
is obligated under CAA section 110(c) to promulgate a FIP for that 
state within 2 years. For a more detailed discussion of CAA section 110 
authority and timelines, refer to Section III.C of this proposed rule.
---------------------------------------------------------------------------

    \68\ National Ambient Air Quality Standards for Ozone, Final 
Rule, 80 FR 65292 (October 26, 2015). Although the level of the 
standard is specified in the units of ppm, ozone concentrations are 
also described in parts per billion (ppb). For example, 0.070 ppm is 
equivalent to 70 ppb.
---------------------------------------------------------------------------

    The EPA is proposing this FIP action now to address twenty-six 
states' good neighbor obligations for the 2015 ozone NAAQS, but the EPA 
will not finalize this FIP action for any state unless and until it has 
issued a final finding of failure to submit or a final disapproval of 
that state's SIP submission. The EPA is not required to wait to propose 
a FIP until after the Agency proposes or finalizes a SIP disapproval or 
makes a finding of failure to submit.\69\ CAA section 110(c) authorizes 
EPA to promulgate a FIP ``at any time within 2 years'' of a SIP 
disapproval or making a finding of failure to submit. Thus, the EPA may 
promulgate a FIP contemporaneously with or immediately following 
predicate final action on a SIP (or finding no SIP was submitted). In 
order to accomplish this, the EPA must necessarily be able to propose a 
FIP prior to taking final action to disapprove a SIP or make a finding 
of failure to submit. The Supreme Court recognized this in EME Homer 
City in holding that the EPA is not obligated to first define a state's 
good neighbor obligations or give the state an additional opportunity 
to submit an approvable SIP before promulgating a FIP: ``EPA is not 
obliged to wait two years or postpone its action even a single day: The 
Act empowers the Agency to promulgate a FIP `at any time' within the 
two-year limit.'' \70\ Furthermore, the D.C. Circuit in Wisconsin held 
that states and EPA are obligated to fully address good neighbor 
obligations for ozone ``as expeditiously as practical'' and in no event 
later than the next relevant downwind attainment dates found in CAA 
section 181(a).\71\ In Maryland v. EPA, the D.C. Circuit made clear 
that Wisconsin's and North Carolina's holdings are fully applicable to 
the Marginal area attainment date for the 2015 ozone NAAQS,\72\ which 
fell on August 3, 2021.\73\ The Wisconsin court emphasized that EPA has 
the authority under CAA section 110 to structure and time its actions 
in a manner such that the Agency can ensure necessary reductions are 
achieved by the downwind attainment dates.\74\
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    \69\ The EPA notes there are three consent decrees to resolve 
three deadline suits related to EPA's duty to act on good neighbor 
SIP submissions for the 2015 ozone NAAQS. In New York et al. v. 
Regan, et al. (No. 1:21-CV-00252, S.D.N.Y.), the EPA agreed to take 
final action on the 2015 ozone NAAQS good neighbor SIP submissions 
from Indiana, Kentucky, Michigan, Ohio, Texas, and West Virginia by 
April 30, 2022; however, if the EPA proposes to disapprove any SIP 
submissions and proposes a replacement FIP by February 28, 2022, 
then EPA's deadline to take final action on that SIP submission is 
extended to December 30, 2022. In Downwinders at Risk et al. v. 
Regan (No. 21-cv-03551, N.D. Cal.), the EPA agreed to take final 
action on the 2015 ozone NAAQS good neighbor SIP submissions from 
Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana, 
Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, 
South Carolina, Tennessee, Texas, West Virginia, and Wisconsin by 
April 30, 2022; however, if the EPA proposes to disapprove any of 
these SIP submissions and proposes a replacement FIP by February 28, 
2022, then EPA's deadline to take final action on that SIP 
submission is December 30, 2022. In this CD, the EPA also agreed to 
take final action on Hawaii's SIP submission by April 30, 2022, and 
to take final action on the SIP submissions of Arizona, California, 
Montana, Nevada, and Wyoming by December 15, 2022. In Our Children's 
Earth Foundation v. EPA (No. 20-8232, S.D.N.Y.), the EPA agreed to 
take final action on the 2015 ozone NAAQS good neighbor SIP 
submission from New York by April 30, 2022; however, if the EPA 
proposes to disapprove New York's SIP submission and proposes a 
replacement FIP by February 28, 2022, then EPA's deadline to take 
final action on New York's SIP submission is extended to December 
30, 2022.
    \70\ See EPA v. EME Homer City Generation, L.P., 572 U.S. 489, 
509 (2014) (citations omitted).
    \71\ Wisconsin v. EPA, 938 F.3d 303, 313-14 (D.C. Cir. 2019) 
(citing North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
    \72\ Maryland v. EPA, 958 F.3d 1185, 1203-04 (D.C. Cir. 2020).
    \73\ See CAA section 181(a); 40 CFR 51.1303; Additional Air 
Quality Designations for the 2015 Ozone National Ambient Air Quality 
Standards, 83 FR 25776 (June 4, 2018, effective August 3, 2018).
    \74\ 938 F.3d at 318 (``When EPA determines a State's SIP is 
inadequate, EPA presumably must issue a FIP that will bring that 
State into compliance before upcoming attainment deadlines, even if 
the outer limit of the statutory timeframe gives EPA more time to 
formulate the FIP.'') (citing Sierra Club v. EPA, 294 F.3d 155, 161 
(D.C. Cir. 2002)).
---------------------------------------------------------------------------

    On February 22, 2022, the EPA proposed to disapprove 19 good 
neighbor SIP submissions (Alabama, Arkansas, Illinois, Indiana, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, New Jersey, New York, Ohio, Oklahoma, Tennessee, Texas, West 
Virginia, Wisconsin).\75\ The EPA is proposing to

[[Page 20058]]

promulgate 2015 ozone NAAQS good neighbor FIPs for these same states, 
as well as California, Nevada, and Wyoming, but will not finalize a FIP 
for any of these states unless and until the EPA formally finalizes 
disapprovals of their SIP submittals or, in the event that any of these 
states withdraw their good neighbor SIP submissions after this 
proposal, makes a finding of failure to submit.\76\ See CAA section 
110(c).
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    \75\ See 87 FR 9463 (Maryland); 87 FR 9484 (New Jersey, New 
York); 87 FR 9498 (Kentucky); 87 FR 9516 (West Virginia); 87 FR 9533 
(Missouri); 87 FR 9545 (Alabama, Mississippi, Tennessee); 87 FR 9798 
(Arkansas, Louisiana, Oklahoma, Texas); 87 FR 9838 (Illinois, 
Indiana, Michigan, Minnesota, Ohio, Wisconsin). EPA has not yet 
proposed action on interstate transport SIPs submitted by 
California, Nevada, Utah, and Wyoming.
    \76\ See the document titled ``Status of CAA Section 
110(a)(2)(D)(i)(I) SIP Submissions for the 2015 Ozone NAAQS for 
States Covered by the Proposed Federal Implementation Plan 
Addressing Regional Ozone Transport for the 2015 Ozone National 
Ambient Air Quality Standards,'' included in the docket for this 
rulemaking, for additional information on EPA's statutory 
authorities for this proposed rule.
---------------------------------------------------------------------------

    Additionally, the EPA has taken action that has triggered EPA's 
obligation under CAA section 110(c) to promulgate FIPs addressing the 
good neighbor provision for some other states. On December 5, 2019, the 
EPA published a rule finding that seven states (Maine, New Mexico, 
Pennsylvania, Rhode Island, South Dakota, Utah, and Virginia) failed to 
submit or otherwise make complete submissions that address the 
requirements of CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone 
NAAQS.\77\ This finding triggered a 2-year deadline for the EPA to 
issue FIPs to address the good neighbor provision for these states by 
January 6, 2022. As the EPA has subsequently received and taken final 
action to approve good neighbor SIPs from Maine, Rhode Island, and 
South Dakota,\78\ the EPA currently has authority under the December 5, 
2019, finding of failure to submit to issue FIPs for New Mexico, 
Pennsylvania, Utah, and Virginia. In this proposal, EPA is issuing 
proposed FIP requirements for Pennsylvania, Utah, and Virginia.\79\
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    \77\ Findings of Failure To Submit a Clean Air Act Section 110 
State Implementation Plan for Interstate Transport for the 2015 
Ozone National Ambient Air Quality Standards (NAAQS), 84 FR 66612 
(December 5, 2019, effective January 6, 2020).
    \78\ Air Plan Approval; Maine and New Hampshire; 2015 Ozone 
NAAQS Interstate Transport Requirements, 86 FR 45870 (August 17, 
2021); Air Plan Approval; Rhode Island; 2015 Ozone NAAQS Interstate 
Transport Requirements, 86 FR 70409 (December 10, 2021); 
Promulgation of State Implementation Plan Revisions; Infrastructure 
Requirements for the 2015 Ozone National Ambient Air Quality 
Standards; South Dakota; Revisions to the Administrative Rules of 
South Dakota, 85 FR 29882 (May 19, 2020).
    \79\ The EPA has not yet taken action on a subsequent good 
neighbor SIP submission from New Mexico or Utah; EPA is not 
including New Mexico in this proposed action.
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C. Other CAA Authorities for This Action

1. Correction of EPA's Determination Regarding Delaware's SIP 
Submission and Its Impact on EPA's FIP Authority for Delaware
    In 2020, the EPA approved an infrastructure SIP submission from 
Delaware for the 2015 ozone NAAQS, which in part addressed the good 
neighbor provision at CAA section 110(a)(2)(D)(i)(I).\80\ The EPA 
concluded that, based on the modeling results presented in a 2018 March 
memorandum and using a 2023 analytic year, Delaware's largest impact on 
any potential downwind nonattainment or maintenance receptor was less 
than 1 percent of the NAAQS.\81\ As a result, the EPA found that 
Delaware would not significantly contribute to nonattainment or 
interfere with maintenance in any other state.\82\ Therefore, the EPA 
approved the portion of Delaware's infrastructure SIP that addressed 
CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone NAAQS.
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    \80\ Approval and Promulgation of Air Quality Implementation 
Plans; Delaware; Infrastructure Requirements for the 2015 Ozone 
Standard and Revisions to Modeling Requirements, 85 FR 25307 (May 1, 
2020).
    \81\ ``Technical Support Document for the Delaware State 
Implementation Plan for the Infrastructure Requirements for the 2015 
Ozone Standard and Revisions to Modeling Requirements'' at 16, 
available in Docket No. EPA-R03-OAR-2019-0663.
    \82\ Id. at 17. Based on the 2023 modeling from the 2018 
memorandum, Delaware was expected in 2023 to have a 0.40 ppb impact 
on a potential nonattainment receptor in Fairfield, Connecticut 
(Site ID 90019003) and a 0.38 ppb impact at a potential maintenance 
receptor in Queens, New York (Site ID 360810124).
---------------------------------------------------------------------------

    Subsequent to the release of the modeling data shared in the March 
2018 memorandum and EPA's approval of Delaware's 2015 ozone NAAQS good 
neighbor SIP submission, the EPA performed updated modeling, as 
described in Section V of this proposed rule. The data from this 
updated air quality modeling now show that Delaware is projected to 
contribute more than 1 percent of the NAAQS to downwind receptors in 
Bristol, Pennsylvania, in the 2023 analytic year.\83\ Therefore, in 
light of the modeling data, EPA is proposing to find that its approval 
of Delaware's 2015 ozone NAAQS infrastructure SIP submission, with 
regard only to the portion addressing the good neighbor provision at 
CAA section 110(a)(2)(D)(i)(I), was in error. Section 110(k)(6) of the 
CAA gives the Administrator authority, without any further submission 
from a state, to revise certain prior actions, including actions to 
approve SIPs, upon determining that those actions were in error.\84\ 
The modeling data demonstrate that EPA's prior conclusion that Delaware 
will not significantly contribute to nonattainment or interfere with 
maintenance in any other state in the 2023 analytic year was incorrect, 
which means that EPA's approval of Delaware's good neighbor SIP 
submission was in error.
---------------------------------------------------------------------------

    \83\ The contribution from Delaware in 2023 to the receptor in 
Bristol, Pennsylvania, is 1.36 ppb.
    \84\ See, e.g., 86 FR 23054, 23068 (error correcting prior 
approval of Kentucky's transport SIP submission for the 2008 ozone 
NAAQS to a disapproval and simultaneously promulgating FIP on the 
basis of the Wisconsin and New York decisions remanding CSAPR Update 
and vacating CSAPR Close-Out and new information establishing 
Kentucky was linked to downwind receptors).
---------------------------------------------------------------------------

    Therefore, the EPA proposes to correct the error in Delaware's good 
neighbor SIP approval. This error correction under CAA section 
110(k)(6) would revise the approval of the portion of Delaware's 2015 
ozone NAAQS infrastructure SIP that addresses CAA section 
110(a)(2)(D)(i)(I) to a disapproval and rescind any statements that the 
portion of Delaware's infrastructure SIP submission that addresses CAA 
section 110(a)(2)(D)(i)(I) satisfies the requirements of the good 
neighbor provision. The EPA is not proposing to correct the elements of 
Delaware's 2015 ozone NAAQS infrastructure SIP that do not address CAA 
section 110(a)(2)(D)(i)(I).
    As discussed in greater detail in the sections that follow, the EPA 
is proposing to determine that there are additional emissions 
reductions that are required for Delaware to satisfy its good neighbor 
obligations for the 2015 ozone NAAQS. The analysis on which the EPA 
proposes this conclusion for Delaware is the same, regionally 
consistent analytical framework on which the Agency proposes FIP action 
for the other states included in this proposal. The Agency recognizes 
that it is possible, based on updated information for the final rule--
as applied within a regionally consistent analytical framework--that 
Delaware (or other states for which the EPA proposes FIPs in this 
action) may be found to have no further interstate transport obligation 
for the 2015 ozone NAAQS. If such a circumstance were to occur, the EPA 
anticipates that it would not finalize this proposed error correction 
or may modify the error correction such that the approval of Delaware's 
portion of the SIP as it relates to its good neighbor obligations may 
be affirmed.

[[Page 20059]]

2. Application of Rule in Indian Country and Necessary or Appropriate 
Finding
    The EPA proposes that this rule will be applicable in all areas of 
Indian country (as defined at 18 U.S.C. 1151) within the covered 
geography of the proposal, as defined below. Currently, certain areas 
of Indian country within the geography of the proposal are subject to 
state implementation planning authority. Other areas of Indian country 
within that geography would be subject to tribal planning authority, 
although none of the relevant tribes have as yet sought eligibility to 
administer a tribal plan to implement the good neighbor provision.\85\ 
As described later, the EPA is proposing to include all areas of Indian 
country within the covered geography, notwithstanding whether those 
areas are currently subject to a state's implementation planning 
authority or the potential planning authority of a tribe.
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    \85\ We note that, consistent with EPA's prior good neighbor 
actions in California, the regulatory ozone monitor located on the 
Morongo Band of Mission Indians (``Morongo'') reservation is a 
projected downwind receptor in 2023. See monitoring site 060651016 
in Table V.D-1. We also note that the Temecula, California 
regulatory ozone monitor is a projected downwind receptor in 2023 
and in past regulatory actions has been deemed representative of air 
quality on the Pechanga Band of Luise[ntilde]o Indians 
(``Pechanga'') reservation. See, e.g., Approval of Tribal 
Implementation Plan and Designation of Air Quality Planning Area; 
Pechanga Band of Luise[ntilde]o Mission Indians, 80 FR 18120, at 
18121-18123 (April 3, 2015); see also monitoring site 060650016 in 
Table V.D-1. The presence of receptors on, or representative of, the 
Morongo and Pechanga reservations does not trigger obligations for 
the Morongo and Pechanga Tribes. Nevertheless, these receptors are 
relevant to EPA's assessment of any linked upwind states' good 
neighbor obligations. See, e.g., Approval and Promulgation of Air 
Quality State Implementation Plans; California; Interstate Transport 
Requirements for Ozone, Fine Particulate Matter, and Sulfur Dioxide, 
83 FR 65093 (December 19, 2018). Under 40 CFR 49.4(a), tribes are 
not subject to the specific plan submittal and implementation 
deadlines for NAAQS-related requirements, including deadlines for 
submittal of plans addressing transport impacts.
---------------------------------------------------------------------------

    With respect to areas of Indian country not currently subject to a 
state's implementation planning authority--i.e., Indian reservation 
lands (with the partial exception of reservation lands located in the 
State of Oklahoma, as described further below) and other areas of 
Indian country over which the EPA or a tribe has demonstrated that a 
tribe has jurisdiction--the EPA here proposes a ``necessary or 
appropriate'' finding that direct federal implementation of the rule's 
requirements is warranted under CAA section 301(d)(4) and 40 CFR 
49.11(a) (the areas of Indian country subject to this finding are 
referred to later as the 301(d) FIP areas). Indian Tribes may, but are 
not required to, submit tribal plans to implement CAA requirements, 
including the good neighbor provision. Section 301(d) of the CAA and 40 
CFR part 49 authorize the Administrator to treat an Indian Tribe in the 
same manner as a state (i.e., TAS) for purposes of developing and 
implementing a tribal plan implementing good neighbor obligations. See 
40 CFR 49.3; see also ``Indian Tribes: Air Quality Planning and 
Management,'' hereafter ``Tribal Authority Rule,'' (63 FR 7254, 
February 12, 1998). The EPA is authorized to directly implement the 
good neighbor provision in the 301(d) FIP areas when it finds, 
consistent with the authority of CAA section 301--which the EPA has 
exercised in 40 CFR 49.11--that it is necessary or appropriate to do 
so.\86\
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    \86\ See Arizona Pub. Serv. Co. v. U.S. E.P.A., 562 F.3d 1116, 
1125 (10th Cir. 2009) (stating that 40 CFR 49.11(a) ``provides the 
EPA discretion to determine what rulemaking is necessary or 
appropriate to protect air quality and requires the EPA to 
promulgate such rulemaking''); Safe Air For Everyone v. U.S. Env't 
Prot. Agency, No. 05-73383, 2006 WL 3697684, at *1 (9th Cir., Dec. 
15, 2006) (``The statutes and regulations that enable EPA to 
regulate air quality on Indian reservations provide EPA with broad 
discretion in setting the content of such regulations.'').
---------------------------------------------------------------------------

    The EPA proposes in this action to find that it is both necessary 
and appropriate to regulate all new and existing EGU and non-EGU 
sources meeting the applicability criteria set forth in this proposed 
rule in all of the 301(d) FIP areas that are located within the 
geographic scope of coverage of the rule. For purposes of this proposed 
finding, the geographic scope of coverage of the rule means the areas 
of the United States encompassed within the borders of the states EPA 
has determined to be linked at Steps 1 and 2 of the 4-step interstate 
transport framework.\87\ For EGU applicability criteria, see Section 
VII.B of this proposed rule; for non-EGU applicability criteria, see 
Section VII.C of this proposed rule. To EPA's knowledge, only one 
existing EGU or non-EGU source is located within the 301(d) FIP areas: 
The Bonanza Power Plant, an EGU source, located on the Uintah and Ouray 
Reservation, geographically located within the borders of Utah.
---------------------------------------------------------------------------

    \87\ With respect to any non-EGU sources located in the 301(d) 
FIP areas, the geographic scope of coverage of this proposed rule 
does not include those states for which EPA proposes to find, based 
on air quality modeling, that no further linkage exists by the 2026 
analytic year at Steps 1 and 2. The states no longer projected to be 
linked in 2026 are Alabama, Delaware, and Tennessee.
---------------------------------------------------------------------------

    This proposed finding is consistent with EPA's prior good neighbor 
rules. In prior rulemakings under the good neighbor provision, the EPA 
has included all areas of Indian country within the geographic scope of 
those FIPs, such that any new or existing sources meeting the rules' 
applicability criteria would be subject to the rule irrespective of 
whether subject to state or tribal underlying CAA planning authority. 
In CSAPR, the CSAPR Update, and the Revised CSAPR Update, the scope of 
the emissions trading programs established for EGUs extended to cover 
all areas of Indian country located within the geographic boundaries of 
the covered states. In these rules, at the time of their promulgation, 
no existing units were located in the covered areas of Indian country; 
under the general applicability criteria of the trading programs, 
however, any new sources locating in such areas would become subject to 
the programs. Thus, EPA established a separate allowance allocation 
that would be available for any new units locating in any of the 
relevant areas of Indian country. See, e.g., 76 FR at 48293 (describing 
the CSAPR methodology of allowance allocation under the ``Indian 
country new unit set-aside'' provisions); see also id. at 48217 
(explaining EPA's source of authority for directly regulating in 
relevant areas of Indian country as necessary or appropriate). Further, 
in any action in which the EPA subsequently approved a state's SIP 
submittal to partially or wholly replace the provisions of a CSAPR FIP, 
EPA has clearly delineated that it will continue to administer the 
Indian country new unit set aside for sources in any areas of Indian 
country geographically located within a state's borders and not subject 
to that state's CAA planning authority, and the state may not exercise 
jurisdiction over any such sources. See, e.g., 82 FR 46674, 46677 
(October 6. 2017) (approving Alabama's SIP submission establishing a 
state CSAPR trading program for ozone season NOX, but 
providing, ``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 this proposed rule, the EPA proposes to take an approach similar 
to the prior CSAPR rulemakings with respect to regulating sources in 
the 301(d) FIP areas.\88\ The EPA believes this approach is necessary 
and appropriate for several reasons. First, the purpose of this rule is 
to address the

[[Page 20060]]

interstate transport of ozone on a national scale, and the technical 
record establishes that the nonattainment and maintenance receptors 
located throughout the country are impacted by sources of ozone 
pollution on a broad geographic scale. The upwind regions associated 
with each receptor typically span at least two, and often far more, 
states. Within the broad upwind region covered by this proposal, the 
EPA proposes to apply--consistent with the methodology of allocating 
upwind responsibility in prior transport rules going back to the 
NOX SIP Call--a uniform level of control stringency. (See 
Section VI of this proposed rule for a discussion of EPA's 
determination of control stringency for this proposal.) Within this 
approach, consistency in rule requirements across all jurisdictions is 
vital in ensuring the remedy for ozone transport is, in the words of 
the Supreme Court, ``efficient and equitable,'' 572 U.S. 489, 519. In 
particular, as the Supreme Court found in EME Homer City Generation, 
allocating responsibility through uniform levels of control across the 
entire upwind geography is ``equitable'' because, by imposing uniform 
cost thresholds on regulated States, EPA's rule subjects to stricter 
regulation those States that have done relatively less in the past to 
control their pollution. Upwind States that have not yet implemented 
pollution controls of the same stringency as their neighbors will be 
stopped from free riding on their neighbors' efforts to reduce 
pollution. They will have to bring down their emissions by installing 
devices of the kind in which neighboring States have already invested. 
Id.
---------------------------------------------------------------------------

    \88\ See Section VII.B.9 of this action for a discussion of 
revisions that are proposed in this rulemaking regarding the point 
in the allowance allocation process at which the EPA would establish 
set-asides of allowances for units in Indian country not subject to 
a state's CAA implementation planning authority.
---------------------------------------------------------------------------

    In the context of addressing regional-scale ozone transport in this 
proposal, a uniform level of stringency that extends to and includes 
the 301(d) FIP areas geographically located within the boundaries of 
the linked upwind states carries significant force. Failure to include 
all such areas within the scope of the rule creates a significant risk 
that these areas may be targeted for the siting of facilities emitting 
ozone-precursor pollutants, in order to avoid the regulatory costs that 
would be imposed under this proposed rule in the surrounding areas of 
state jurisdiction. Electricity generation or the production of other 
goods and commodities may become more cost-competitive at any EGUs or 
non-EGUs not subject to the rule but located in a geography where all 
surrounding facilities in the same industrial category are subject to 
the rule. For instance, the affected EGU source located on the Uintah 
and Ouray Reservation of the Ute Tribe is in an area that is 
interconnected with the western electricity grid and is owned and 
operated by an entity that generates and provides electricity to 
customers in several states. It is both necessary and appropriate, in 
EPA's view, to avoid creating, via this proposed rule, a structure of 
incentives that may cause generation or production--and the associated 
NOX emissions--to shift into the 301(d) FIP areas to escape 
regulation needed to eliminate interstate transport under the good 
neighbor provision.
    The EPA believes it is appropriate to propose direct federal 
implementation of the proposed rule's requirements in the 301(d) FIP 
areas at this time rather than at a later date. Tribes have the 
opportunity to seek TAS and to undertake tribal implementation plans 
under the CAA. To date, the one tribe which could develop and seek 
approval of a tribal implementation plan to address good neighbor 
obligations with respect to an existing EGU in the 301(d) FIP areas for 
the 2015 ozone NAAQS (or for any other NAAQS), the Ute Indian Tribe of 
the Uintah and Ouray Reservation, has not expressed an intent to do so. 
Nor has the EPA heard such intentions from any other tribe, and it 
would not be reasonable to expect tribes to undertake that planning 
effort, particularly when no existing sources are currently located on 
their lands. Further, the EPA is mindful that under court precedent, 
the EPA and states generally bear an obligation to fully implement any 
required emissions reductions to eliminate significant contribution 
under the good neighbor provision as expeditiously as practicable and 
in alignment with downwind areas' attainment schedule under the Act. As 
discussed in Section VII.A of this proposed rule, the EPA anticipates 
implementing certain required emissions reductions by the 2023 ozone 
season, the last full ozone season before the 2024 Moderate area 
attainment date, and other key additional required emissions reductions 
by the 2026 ozone season, the last full ozone season before the 2027 
Serious area attainment date. Absent this proposed federal 
implementation plan in the 301(d) FIP areas, NOX emissions 
from any existing or new EGU or non-EGU sources located in, or locating 
in, the 301(d) FIP areas within the covered geography of the rule would 
remain unregulated and could potentially increase. This would be 
inconsistent with EPA's overall goal of aligning good neighbor 
obligations with the downwind areas' attainment schedule and to achieve 
emissions reductions as expeditiously as practicable.
    Further, the EPA recognizes that Indian country, including the 
301(d) FIP areas, is often home to communities with environmental 
justice concerns, and these communities may bear a disproportionate 
level of pollution burden as compared with other areas of the United 
States. EPA's draft Strategic Plan for Fiscal Year 2022-2026 \89\ 
includes an objective to promote environmental justice at the Federal, 
Tribal, state, and local levels and states: ``Integration of 
environmental justice principles into all EPA activities with Tribal 
governments and in Indian country is designed to be flexible enough to 
accommodate EPA's Tribal program activities and goals, while at the 
same time meeting the Agency's environmental justice goals.'' By 
including all areas of Indian country within the covered geography of 
the rule, the EPA is advancing environmental justice, lowering 
pollution burdens in such areas, and preventing the potential for 
``pollution havens'' to form in such areas as a result of facilities 
seeking to locate there to avoid the requirements that would otherwise 
apply outside of such areas under this proposed rule.
---------------------------------------------------------------------------

    \89\ https://www.epa.gov/system/files/documents/2021-10/fy-2022-2026-epa-draft-strategic-plan.pdf
---------------------------------------------------------------------------

    Therefore, in order to ensure timely alignment of all needed 
emissions reductions with the larger timetable of this proposed rule, 
to ensure equitable distribution of the upwind pollution reduction 
obligation across all upwind jurisdictions, to avoid perverse economic 
incentives to locate sources of ozone-precursor pollution in the 301(d) 
FIP areas, and to deliver greater environmental justice to tribal 
communities in line with Executive Order 13985: Advancing Racial Equity 
and Support for Underserved Communities Through the Federal 
Government,\90\ EPA proposes to find it both necessary and appropriate 
that all existing and new EGU and non-EGU sources that are located in 
the 301(d) FIP areas within the geographic boundaries of the covered 
states, and which would be subject to this rule if located within areas 
subject to state CAA planning authority, should be included in this 
rule. The EPA proposes this finding under section 301(d)(4) of the Act 
and 40 CFR 49.11. Further, in order to avoid ``unreasonable delay'' in

[[Page 20061]]

promulgating this FIP, as required under section 49.11, the EPA 
believes it is appropriate to make this proposed finding now, in order 
to align emissions reduction obligations for any covered new or 
existing sources in the 301(d) FIP areas with the larger schedule of 
reductions under this proposed rule. Because all other covered EGU and 
non-EGU sources within the geography of this proposed rule would be 
subject to emissions reductions of uniform stringency beginning in the 
2023 ozone season, and as necessary to fully and expeditiously address 
good neighbor obligations for the 2015 ozone NAAQS, there is little 
benefit to be had by not proposing to include the 301(d) FIP areas in 
this rule now and a potentially significant downside to not doing so.
---------------------------------------------------------------------------

    \90\ Executive Order 13985 (January 20, 2021): https://www.whitehouse.gov/briefing-room/presidential-actions/2021/01/20/executiveorder-advancing-racial-equity-and-support-for-underserved-communities-through-the-federal-government/.
---------------------------------------------------------------------------

    The Agency recognizes that Tribal governments may still choose to 
seek TAS to develop a Tribal plan with respect to the obligations under 
this proposed rule, and this proposed determination does not preclude 
the tribes from taking such actions. The EPA will continue to consult 
with the government of the Ute Indian Tribe of the Uintah and Ouray 
Reservation, and any other tribe wishing to continue consultation, 
during the comment period for this proposal. The EPA invites comment on 
this proposed finding.
a. Indian Country Subject to State Implementation Planning Authority
    Following the U.S. Supreme Court decision in McGirt v. Oklahoma, 
140 S. Ct. 2452 (2020), the Governor of the State of Oklahoma requested 
approval under Section 10211(a) of the Safe, Accountable, Flexible, 
Efficient Transportation Equity Act of 2005: A Legacy for Users, Public 
Law 109-59, 119 Stat. 1144, 1937 (August 10, 2005) (``SAFETEA''), to 
administer in certain areas of Indian country (as defined at 18 U.S.C. 
1151) the State's environmental regulatory programs that were 
previously approved by the EPA for areas outside of Indian country. The 
State's request excluded certain areas of Indian country further 
described later. In addition, the State only sought approval to the 
extent that such approval is necessary for the State to administer a 
program in light of Oklahoma Dept. of Environmental Quality v. EPA, 740 
F.3d 185 (D.C. Cir. 2014).\91\
---------------------------------------------------------------------------

    \91\ In ODEQ v. EPA, the D.C. Circuit held that under the CAA, a 
state has the authority to implement a SIP in non-reservation areas 
of Indian country in the state, where there has been no 
demonstration of tribal jurisdiction. Under the D.C. Circuit's 
decision, the CAA does not provide authority to states to implement 
SIPs in Indian reservations. ODEQ did not, however, substantively 
address the separate authority in Indian country provided 
specifically to Oklahoma under SAFETEA. That separate authority was 
not invoked until the State submitted its request under SAFETEA, and 
was not approved until EPA's decision, described in this section, on 
October 1, 2020.
---------------------------------------------------------------------------

    On October 1, 2020, the EPA approved Oklahoma's SAFETEA request to 
administer all the State's EPA-approved environmental regulatory 
programs, including the Oklahoma SIP, in the requested areas of Indian 
country.\92\ As requested by Oklahoma, the EPA's approval under SAFETEA 
does not include Indian country lands, including rights-of-way running 
through the same, that: (1) Qualify as Indian allotments, the Indian 
titles to which have not been extinguished, under 18 U.S.C. 1151(c); 
(2) are held in trust by the United States on behalf of an individual 
Indian or Tribe; or (3) are owned in fee by a Tribe, if the Tribe (a) 
acquired that fee title to such land, or an area that included such 
land, in accordance with a treaty with the United States to which such 
Tribe was a party, and (b) never allotted the land to a member or 
citizen of the Tribe (collectively ``excluded Indian country lands'').
---------------------------------------------------------------------------

    \92\ Available in the docket for this rulemaking.
---------------------------------------------------------------------------

    EPA's approval under SAFETEA expressly provided that to the extent 
EPA's prior approvals of Oklahoma's environmental programs excluded 
Indian country, any such exclusions are superseded for the geographic 
areas of Indian country covered by EPA's approval of Oklahoma's SAFETEA 
request.\93\ The approval also provided that future revisions or 
amendments to Oklahoma's approved environmental regulatory programs 
would extend to the covered areas of Indian country (without any 
further need for additional requests under SAFETEA).
---------------------------------------------------------------------------

    \93\ EPA's prior approvals relating to Oklahoma's SIP frequently 
noted that the SIP was not approved to apply in areas of Indian 
country (consistent with the D.C. Circuit's decision in ODEQ v. EPA) 
located in the state. See, e.g., 85 FR 20178, 20180 (April 10, 
2020). Such prior expressed limitations are superseded by EPA's 
approval of Oklahoma's SAFETEA request.
---------------------------------------------------------------------------

    In a Federal Register notice published on February 22, 2022 (87 FR 
9798), the EPA proposed to disapprove the portion of an Oklahoma SIP 
submittal pertaining to the state's interstate transport obligations 
under CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone NAAQS. 
Consistent with the D.C. Circuit's decision in ODEQ v. EPA and with 
EPA's October 1, 2020 SAFETEA approval, if this disapproval is 
finalized as proposed, EPA will have authority under CAA section 110(c) 
to promulgate a FIP as needed to address the disapproved aspects of the 
State's good neighbor SIP submittal.\94\ In accordance with the 
discussion above, EPA's FIP authority in this circumstance would extend 
to all Indian country in Oklahoma, other than the excluded Indian 
country lands, as described previously.\95\ Because--per the State's 
request under SAFETEA--EPA's October 1, 2020 approval does not displace 
any SIP authority previously exercised by the State under the CAA as 
interpreted in ODEQ v. EPA, EPA's FIP authority under CAA section 
110(c) would also apply to any Indian allotments or dependent Indian 
communities located outside of an Indian reservation over which there 
has been no demonstration of tribal authority. EPA's FIP authority 
under CAA section 110(c) would similarly apply to Indian allotments or 
dependent Indian communities located outside of an Indian reservation 
over which there has been no demonstration of tribal authority located 
in any other state within the geographic scope of this proposed rule.
---------------------------------------------------------------------------

    \94\ The antecedent fact that the state had the authority and 
jurisdiction to implement requirements under the good neighbor 
provision, in EPA's view, supplies the condition necessary for the 
Agency to exercise its FIP authority to the extent the EPA has 
disapproved the state's SIP submission with respect to those 
requirements. Under CAA section 110(c), the EPA ``stands in the 
shoes of the defaulting state, and all of the rights and duties that 
would otherwise fall to the state accrue instead to the EPA.'' 
Central Ariz. Water Conservation Dist. v. EPA, 990 F.2d 1531, 1541 
(9th Cir. 1993).
    \95\ With respect to those areas of Indian country constituting 
``excluded Indian country lands'' in the State of Oklahoma, as 
defined above, the EPA proposes to apply the same necessary or 
appropriate finding as set forth above with respect to all other 
301(d) FIP areas within the geographic scope of coverage of the 
rule.
---------------------------------------------------------------------------

    In light of the relevant legal authorities discussed above 
regarding the scope of the State of Oklahoma's regulatory jurisdiction 
under the CAA, the EPA has FIP authority under CAA section 110(c) with 
respect to all Indian country in Oklahoma other than excluded Indian 
country lands. To the extent any change occurs in the scope of 
Oklahoma's SIP authority in Indian country before the finalization of 
this proposed rule, such a change may affect the ability of the Agency 
to exercise the FIP authority provided under section 110(c) of the 
Act.\96\ In that eventuality,

[[Page 20062]]

and to the extent any such areas would then fall more appropriately 
within the 301(d) FIP areas as described earlier in this section, EPA's 
proposed necessary or appropriate finding as set forth above with 
respect to all other 301(d) FIP areas within the geographic scope of 
coverage of the rule would then apply.
---------------------------------------------------------------------------

    \96\ On December 22, 2021, the EPA proposed to withdraw and 
reconsider the October 1, 2020, SAFETEA approval. See https://www.epa.gov/ok/proposed-withdrawal-and-reconsideration-and-supporting-information. The EPA is engaging in further consultation 
with tribal governments and expects to have discussions with the 
State of Oklahoma as part of this reconsideration. The EPA also 
notes that the October 1, 2020, approval is the subject of a pending 
challenge in federal court. Pawnee Nation of Oklahoma v. Regan, No. 
20-9635 (10th Cir.).
---------------------------------------------------------------------------

V. Analyzing Downwind Air Quality Problems and Contributions From 
Upwind States

A. Selection of Analytic Years for Evaluating Ozone Transport 
Contributions to Downwind Air Quality Problems

    In this section, the EPA describes its process for selecting 
analytic years for air quality modeling and analyses performed to 
identify nonattainment and maintenance receptors and identify upwind 
state linkages. For this proposed rule, the EPA evaluated air quality 
to identify receptors at Step 1 for three analytic years: 2023, 2026, 
and 2032. The EPA evaluated interstate contributions to these receptors 
from individual upwind states at Step 2 for two of these analytic 
years: 2023 and 2026. In selecting these years, the EPA views 2023 and 
2026, in particular, to constitute years by which key emissions 
reductions from EGUs and non-EGUS can be implemented ``as expeditiously 
as practicable.'' (The EPA explains in detail in Section VII of this 
proposed rule its proposed determination that the necessary emissions 
reductions cannot be achieved any more quickly.) In addition, these 
years are the last full ozone seasons before the Moderate and Serious 
area attainment dates for the 2015 ozone NAAQS (ozone seasons run each 
year from May 1-September 30). In order to demonstrate attainment by 
these deadlines, downwind states would be required to rely on design 
values calculated using ozone design values from 2021 through 2023 and 
2024 through 2026, respectively. By focusing its analysis, and, 
potentially, achieving emissions reductions by, the last full ozone 
seasons before the attainment dates (i.e., in 2023 or 2026), this 
proposed rule, if finalized, can assist the downwind areas with 
demonstrating attainment or receiving extensions of attainment dates 
under CAA section 181(a)(5).
    It would not make sense for the EPA to analyze any earlier year 
than 2023. EPA continues to interpret the good neighbor provision as 
forward-looking, based on Congress's use of the future-tense ``will'' 
in section 110(a)(2)(D)(i), an interpretation upheld in Wisconsin, 938 
F.3d at 322. It would be ``anomalous,'' id., for the EPA to impose good 
neighbor obligations in 2023 and future years based solely on finding 
that ``significant contribution'' had existed at some time in the past. 
Id.
    Applying this framework in this proposal, the EPA recognizes that 
the 2021 Marginal area attainment date has already passed. Further, 
based on the timing of this proposal, it will not be possible to 
finalize this rulemaking before the 2022 ozone season has also passed. 
Thus, EPA has selected 2023 as the first appropriate future analytic 
year for this proposed rule because it reflects implementation of good 
neighbor obligations as expeditiously as practicable and coincides with 
the August 3, 2024, Moderate area attainment date established for the 
2015 ozone NAAQS.
    The EPA conducted additional analysis for the 2026 and 2032 
analytic years in order to ensure a complete Step 3 analysis for future 
ozone transport contributions to downwind areas. These years also 
coincide with the last full ozone seasons before future attainment 
dates for the 2015 ozone NAAQS, and 2026 coincides with the ozone 
season by which key additional emissions reductions from EGUs and non-
EGUs become available. Thus, the EPA analyzed additional years beyond 
2023 to determine whether any additional emissions reductions that are 
impossible to obtain by the 2024 attainment date could still be 
necessary in order to fully address significant contribution, taking 
into account the 2027 Serious area attainment date and the 2033 Severe 
area attainment date for the 2015 ozone NAAQS. In all cases, the 
proposed implementation of necessary emissions reductions is as 
expeditiously as practicable, with all possible emissions reductions 
implemented by the next applicable attainment date.
    The timing framework and selection of analytic years set forth 
above comports with the D.C. Circuit's direction in Wisconsin that 
implementing good neighbor obligations beyond the dates established for 
attainment may be justified on a proper showing of impossibility or 
necessity. See 938 F.3d at 320.
    The remainder of this section includes information on (1) the air 
quality modeling platform used in support of the proposed rule with a 
focus on the base year and future year base case emissions inventories, 
(2) the method for projecting design values in 2023, 2026, and 2032, 
and (3) the approach for calculating ozone contributions from upwind 
states. The Agency also provides the design values for nonattainment 
and maintenance receptors and the predicted interstate contributions 
that are at or above the 1 percent of the NAAQS screening threshold. 
The 2016 base period and 2023, 2026, and 2032 future design values and 
contributions for all ozone monitoring sites are provided in the docket 
for this proposed rule. The Air Quality Modeling Technical Support 
Document (AQM TSD) in the docket for this proposed rule contains more 
detailed information on the air quality modeling aspects of this rule.

B. Overview of Air Quality Modeling Platform

    The EPA used version 2 of the 2016-based modeling platform for the 
air quality modeling for this proposed rule. This modeling platform 
includes 2016 base year emissions from anthropogenic and natural 
sources and 2016 meteorology. The platform also includes anthropogenic 
emissions projections for 2023, 2026, and 2032. The emissions data 
contained in this platform represent an update to the 2016 version 1 
inventories that were developed by the EPA, the Multi-Jurisdictional 
Organizations (MJOs), and state and local air agencies as part of the 
Emissions Inventory Collaborative Process.
    The air quality modeling for this proposal was performed for a 
modeling region (i.e., modeling domain) that covers the contiguous 48 
states using a horizontal resolution of 12 x 12 km. The EPA used the 
CAMx version 7.10 for air quality modeling since this was the most 
recent version of CAMx available at the time the air quality modeling 
was performed.\97\ Additional information on the 2016-based air quality 
modeling platform can be found in the AQM TSD.
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    \97\ Ramboll Environment and Health, January 2021, http://www.camx.com.
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C. Emissions Inventories

    The EPA developed emissions inventories for this proposal, 
including emissions estimates for EGUs, non-EGU point sources, 
stationary nonpoint sources, onroad mobile sources, nonroad mobile 
sources, other mobile sources, wildfires, prescribed fires, and 
biogenic emissions that are not the direct result of human activities. 
EPA's air quality modeling relies on this comprehensive set of 
emissions inventories because emissions from multiple source categories 
are needed to model ambient air quality and to facilitate comparison of 
model outputs with ambient measurements.

[[Page 20063]]

    To prepare the emissions inventories for air quality modeling, the 
EPA processed the emissions inventories using the Sparse Matrix 
Operator Kernel Emissions (SMOKE) Modeling System version 4.8.1 to 
produce the gridded, hourly, speciated, model-ready emissions for input 
to the air quality model. Additional information on the development of 
the emissions inventories and on data sets used during the emissions 
modeling process are provided in the TSD titled, ``Preparation of 
Emissions Inventories for the 2016v2 North American Emissions Modeling 
Platform,'' hereafter known as the ``Emissions Modeling TSD.'' This TSD 
is available in the docket for this rule.
1. Foundation Emissions Inventory Data Sets
    The 2016v2 emissions platform is comprised of data from various 
sources including data developed using models, methods, and source 
datasets that became available in calendar years 2020 and 2021, in 
addition to data from the Inventory Collaborative 2016 version 1 
(2016v1) Emissions Modeling Platform, released in October 2019. The 
2016v1 platform was developed through a national collaborative effort 
between the EPA and state and local agencies along with MJOs and 
included emissions inventories for the years 2016, 2023, and 2028. For 
this proposed rule, emissions inventories were developed for the years 
2016, 2023, 2026, and 2032 that represent changes in activity data and 
of predicted emissions reductions from on-the-books actions, planned 
emissions control installations, and promulgated federal measures that 
affect anthropogenic emissions.\98\ The 2016 emissions inventories for 
the U.S. include data derived from the 2017 National Emissions 
Inventory (2017NEI) and some data derived from the 2014 National 
Emissions Inventory (NEI), version 2 (2014NEIv2). All of the inventory 
sectors were updated to better represent the year 2016 through the 
incorporation of 2016-specific state and local data along with 
nationally applied adjustment methods. The following sections provide 
an overview of the construct of the 2016v2 emissions and projections.
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    \98\ Biogenic emissions and emissions from wildfires and 
prescribed fires were held constant between 2016 and the future 
years because (1) these emissions are tied to the 2016 
meteorological conditions and (2) the focus of this rule is on the 
contribution from anthropogenic emissions to projected ozone 
nonattainment and maintenance.
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2. Development of Emissions Inventories for EGUs
    Annual NOX and SO2 emissions for EGUs in the 
2016 base year inventory are based primarily on data from continuous 
emissions monitoring systems (CEMS) and other monitoring systems 
allowed for use by qualifying units under 40 CFR part 75, with other 
EGU pollutants estimated using emissions factors and annual heat input 
data reported to the EPA. For EGUs not reporting under part 75, the EPA 
used data submitted to the NEI and the 2016v1 platform by the states. 
Emissions data for EGUs that did not have data provided for the year 
2016 were pulled forward from data submitted for the 2014 NEI. The Air 
Emissions Reporting Rule, (80 FR 8787; February 19, 2015), requires 
that Type A point sources large enough to meet or exceed specific 
thresholds for emissions be reported to the EPA every year, while the 
smaller Type B point sources must only be reported to EPA every 3 
years.
    The EPA projected future 2023, 2026, and 2032 baseline EGU 
emissions using the version 6--Summer 2021 Reference Case of the 
Integrated Planning Model (IPM). \IPM,\ developed by ICF Consulting, is 
a state-of-the-art, peer-reviewed, multi-regional, dynamic, 
deterministic linear programming model of the contiguous U.S. electric 
power sector. It provides forecasts of least cost capacity expansion, 
electricity dispatch, and emissions control strategies while meeting 
energy demand and environmental, transmission, dispatch, and 
reliability constraints. The EPA has used IPM for over two decades, 
including all prior implemented CSAPR rulemakings, to better understand 
power sector behavior under future business-as-usual conditions and to 
evaluate the economic and emissions impacts of prospective 
environmental policies. The model is designed to reflect electricity 
markets as accurately as possible. The EPA uses the best available 
information from utilities, industry experts, gas and coal market 
experts, financial institutions, and government statistics as the basis 
for the detailed power sector modeling in IPM. The model documentation 
provides additional information on the assumptions discussed here as 
well as all other model assumptions and inputs.\99\
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    \99\ Detailed information and documentation of EPA's Base Case, 
including all underlying assumptions, data sources, and architecture 
parameters can be found on EPA's website at: https://www.epa.gov/airmarkets/epas-power-sector-modeling-platform-v6-using-ipm-summer-2021-reference-case.
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    The IPM version 6--Summer 2021 Reference Case incorporated recent 
updates through the Summer of 2021 to account for updated federal and 
state environmental regulations (including Renewable Portfolio 
Standards (RPS), Clean Energy Standards (CES) and other state 
mandates), fleet changes (committed EGU retirements and new builds), 
electricity demand, technology cost and performance assumptions from 
recent data (for renewables adopting from National Renewable Energy Lab 
(NREL's) Annual Technology Baseline 2020 and for fossil sources from 
U.S. Energy Information Agency's (EIA) Annual Energy Outlook (AEO) 
2020. Natural gas and coal price projections reflect data developed in 
Fall 2020. The inventory of EGUs provided as an input to the model was 
the National Electric Energy Data System (NEEDS) Summer 2021 version 
and is available on EPA's website.\100\ This version of NEEDS reflects 
announced retirements and under construction new builds known as of 
early summer 2021. This projected base case accounts for the effects of 
the finalized Mercury and Air Toxics Standards rule, CSAPR, the CSAPR 
Update, the Revised CSAPR Update, New Source Review settlements, the 
final Effluent Limitation Guidelines (ELG) Rule, the Coal Combustion 
Residual (CCR) Rule, and other on-the-books federal and state rules 
(including renewable energy tax credit extensions from the Consolidated 
Appropriations Act of 2021) through early 2021 impacting 
SO2, NOX, directly emitted particulate matter, 
CO2, and power plant operations. It also includes final 
actions the EPA has taken to implement the Regional Haze Rule and BART 
requirements. IPM has projected output years for 2023 and 2025. IPM 
year 2025 outputs were adjusted for known retirements to be reflective 
of year 2026, and IPM year 2030 outputs were used for the year 2032 as 
is specified by the mapping of IPM output years to specific years.
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    \100\ Available at https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
---------------------------------------------------------------------------

    Additional 2023 through 2026 EGU emissions baseline levels were 
developed through engineering analytics as an alternative approach that 
did not involve IPM. The EPA developed this inventory for use in Step 3 
of this final rule, where it determines emissions reduction potential 
and corresponding state-level emissions budgets. IPM includes 
optimization and perfect foresight in solving for least cost dispatch. 
Given that this final rule will likely become effective immediately 
prior to the start of the 2023 ozone season, the EPA is adopting a 
similar approach to the CSAPR Update and the

[[Page 20064]]

Revised CSAPR Update where it relied on IPM in a relative way in Step 3 
to avoid overstating optimization and dispatch decisions in state-
emissions budget quantification that may not be possible in a short 
time frame. The EPA does this by using the difference in emissions rate 
observed between IPM runs with and without the cost threshold applied, 
rather than using absolute values. In both the CSAPR Update and in this 
rule at Step 3, EPA complemented that projected IPM EGU outlook with 
historical (e.g., engineering analytics) perspective based on 
historical data that only factors in known changes to the fleet. This 
2023 engineering analytics data set is described in more detail in the 
Ozone Transport Policy Analysis Proposed Rule TSD and corresponding 
Appendix A: State Emissions Budgets Calculations and Underlying Data. 
The Engineering Analysis used in Step 3 is also discussed further in 
Section VII.B of this proposed rule.
    Both IPM and the Engineering Analytics tools are valuable for 
estimating future EGU emissions and examining the cone of uncertainty 
around any future sector-level inventory estimate. A key difference 
between the two tools is that IPM reflects both announced and projected 
changes in fleet operation, whereas the Engineering Analytics tool only 
reflects announced changes. By not including projected changes that are 
anticipated in response to market forces and fleet trends, the 
Engineering Analysis is deliberately conservative in its estimate of 
change in the power sector. Throughout all of the CSAPR rules to date, 
and prior interstate transport actions, the EPA has used IPM at Steps 1 
and 2 as it is best suited for projecting emissions in an airshed, at 
projecting emissions for time horizons more than a few years out (for 
which changes would not yet be announced and thus projecting changes is 
critical), and for scenarios where the assumed change in emissions is 
not being codified into a state emissions reduction requirement. Using 
IPM at Steps 1 and 2 helps the EPA avoid overstating future year 
receptor values (Step 1) and future year linkages (Step 2) by 
reflecting reductions anticipated to occur within the airshed in the 
relevant timeframe.
    Engineering analytics has been a useful tool for Step 3 state-level 
emissions reduction estimates in CSAPR rulemaking, because at that step 
EPA is dealing with more geographic granularity (state-level as opposed 
to regional air shed), more near-term (as opposed to medium-term) 
assessments, and scenarios where reduction estimates are codified into 
regulatory requirements. Using the Engineering Analytics tool at this 
step ensures that the EPA is not codifying into the base case, and 
consequently into state emissions budgets, changes in the power sector 
that are merely modeled to occur rather than announced by real-world 
actors.
    Finally, both in the Revised CSAPR Update and in this rule, the EPA 
was able to use the Air Quality Assessment Tool to verify that 
regardless of which EGU inventory is used, the 2023 starting geography 
of the program is not impacted. In other words, regardless of whether a 
stakeholder takes a more comprehensive view of the EGU future (IPM) or 
a more conservative view of change in the EGU fleet (Engineering 
Analysis) the starting geography would be the same. This finding is 
consistent with the observation that EGUs are now less than 10% of the 
total ozone-season NOX inventory and the degree of near-term 
difference between the IPM and Engineering Analytic regional 
projections is relatively small on the regional level. While the EPA 
continues to believe that IPM is best suited for Step 1 and Step 2, and 
engineering analytics is best suited for Step 3 efforts in this 
rulemaking, the Agency is requesting comment on the EGU emissions 
inventory most reasonable for Step 1 and Step 2 in the analysis. The 
Ozone Transport Policy Analysis Proposed Rule TSD contains data on 2023 
and 2026 AQ impacts of each dataset.
3. Development of Emissions Inventories for Non-EGU Point Sources
    The updates to the non-EGU point source emissions include a few 
sources being moved to the EGU inventory and additional control 
efficiency information for the year 2016. In the 2016v2 platform, some 
non-EGU point source emissions were based on data submitted for 2016, 
others were projected from 2014 to 2016, and the emissions for any 
remaining small sources were kept at 2014 levels. Prior to air quality 
modeling, the emissions inventories were processed into a format that 
is appropriate for the air quality model to use. The future year non-
EGU point inventories were grown from 2016 to the future years using 
factors based on the AEO 2021 except for limited cases where errors 
were identified with the AEO 2021 data in which case data from AEO 2020 
were used. The future year inventories reflect emissions reductions due 
to national and local rules, control programs, plant closures, consent 
decrees, and settlements. Reductions from several Maximum Achievable 
Control Technology and National Emissions Standards for Hazardous Air 
Pollutants (NESHAP) standards are included. Projection approaches for 
corn ethanol and biodiesel plants, refineries and upstream impacts 
represent requirements pursuant to the Energy Independence and Security 
Act of 2007 (EISA).
    Aircraft emissions and ground support equipment at airports are 
represented as point sources and are based on adjustments to emissions 
in the January 2021 version of the 2017 NEI (see https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data 
for data and a TSD). A notable update in the January 2021 version of 
the 2017 NEI as compared to the April 2020 version was a correction to 
some double counting of some airport emissions. This correction is 
incorporated into the inventories for this proposed rule. The EPA 
developed and applied factors to adjust the 2017 airport emissions to 
2016, 2023, 2026, and 2032 based on activity growth projected by the 
Federal Aviation Administration 2019 Terminal Area Forecast \101\ 
system, the latest available version at the time the factors were 
developed.
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    \101\ https://www.faa.gov/data_research/aviation/taf/.
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    Emissions at rail yards were represented as point sources. The 2016 
rail yard emissions are largely consistent with the 2017 NEI rail yard 
emissions. The 2016 and 2023 rail yard emissions were developed through 
the 2016v1 Inventory Collaborative process, with the 2026 emissions 
interpolated between the 2023 and 2028 emissions from 2016v1 rail yard 
emissions were interpolated from the 2016 and 2023 emissions. Class I 
rail yard emissions were projected based on the AEO freight rail energy 
use growth rate projections for 2016, 2023, and 2032 with the fleet mix 
assumed to be constant throughout the period.
    Point source oil and gas emissions for 2016 were based on the 
2016v1 point inventory except that an inventory generated by the 
Western Regional Air Partnership (WRAP) \102\ was used for the states 
of Colorado, Montana, New Mexico, North Dakota, South Dakota, Utah, and 
Wyoming. The 2016 oil and gas inventories were first projected to 2019 
values based on actual production data, and those 2019 emissions were 
projected to 2023, 2026, and 2032 using regional projection factors by 
product type based on AEO 2021 projections. NOX and VOC 
reductions that are co-

[[Page 20065]]

benefits to the NESHAP and New Source Performance Standards (NSPS) for 
Stationary Reciprocating Internal Combustion Engines (RICE) are 
reflected for select source categories. In addition, Natural Gas 
Turbines and Process Heaters NSPS NOX controls and NSPS Oil 
and Gas VOC controls \103\ are reflected for select source categories. 
The WRAP future year inventory was used in WRAP states in all future 
years.\104\
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    \102\ http://www.wrapair2.org/pdf/WRAP_OGWG_Report_Baseline_17Sep2019.pdf.
    \103\ On November 15, 2021, the EPA published proposed revisions 
to standards of performance for new, reconstructed, and modified 
sources and proposed revisions to emissions guidelines for existing 
sources in the oil and natural gas sector at 86 FR 63110. Emissions 
reductions from proposed federal regulatory programs are not 
included in EPA's baseline analyses until they have been finalized.
    \104\ http://www.wrapair2.org/pdf/WRAP_OGWG_2028_OTB_RevFinalReport_05March2020.pdf.
---------------------------------------------------------------------------

4. Development of Emissions Inventories for Onroad Mobile Sources
    Onroad mobile sources include exhaust, evaporative, and brake and 
tire wear emissions from vehicles that drive on roads, parked vehicles, 
and vehicle refueling. Emissions from vehicles using regular gasoline, 
high ethanol gasoline, diesel fuel, and electric vehicles were 
represented, along with buses that used compressed natural gas. The EPA 
developed the onroad mobile source emissions for states other than 
California using EPA's Motor Vehicle Emissions Simulator (MOVES). 
MOVES3 was released in November 2020 and has been followed by some 
minor releases that improved the usage of the model but that do not 
have substantive impacts on the emissions estimates. For this proposal, 
MOVES3 was run using inputs provided by state and local agencies 
through the 2017 NEI where available, in combination with nationally 
available data sets to develop a complete inventory. Onroad emissions 
for 2016v2 were developed based on emissions factors output from MOVES3 
run for the year 2016, coupled with activity data (e.g., vehicle miles 
traveled and vehicle populations) representing the year 2016. The 2016 
activity data were provided by some state and local agencies through 
the 2016v1 process, and the remaining activity data were derived from 
the 2017 NEI. The onroad emissions were computed within SMOKE by 
multiplying emissions factors developed using MOVES with the 
appropriate activity data. Onroad mobile source emissions for 
California were consistent with the emissions data provided by the 
state.
    The future-year emissions estimates for onroad mobile sources 
represent all national control programs known at the time of modeling 
including rules newly added in MOVES3: The Greenhouse Gas Emissions and 
Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and 
Vehicles (HDGHG)--Phase 2 \105\ and the Safer Affordable Fuel-Efficient 
(SAFE) Vehicles Rule.\106\ Other finalized rules incorporated into the 
onroad mobile source emissions estimates include: Tier 3 Standards 
(March 2014), the Light-Duty Greenhouse Gas Rule (March 2013), Heavy 
(and Medium)-Duty Greenhouse Gas Rule (August 2011), the Renewable Fuel 
Standard (February 2010), the Light Duty Greenhouse Gas Rule (April 
2010), the Corporate-Average Fuel Economy standards for 2008-2011 
(April 2010), the 2007 Onroad Heavy-Duty Rule (February 2009), and the 
Final Mobile Source Air Toxics Rule (MSAT2) (February 2007). Estimates 
of the impacts of rules that were in effect in 2016 are included in the 
2016 base year emissions at a level that corresponds to the extent to 
which each rule had penetrated into the fleet and fuel supply by the 
year 2016. Local control programs such as the California LEV III 
program for criteria pollutants are included in the onroad mobile 
source emissions.
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    \105\ The effect of the HDGHG Phase 2 rule on criteria 
pollutants is estimated in Table 5-48 of the Regulatory Impact 
Analysis, available from https://nepis.epa.gov/Exe/ZyPDF.cgi/P100P7NS.PDF?Dockey=P100P7NS.PDF.
    \106\ Information on the SAFE vehicles rule is available from 
https://www.epa.gov/regulations-emissions-vehicles-and-engines/safer-affordable-fuel-efficient-safe-vehicles-final-rule. 
Preliminary analysis by the Office of Transportation and Air Quality 
of the impact of this rule on criteria pollutants show impacts of 
less than 1 percent for VOC and no impact for NOX.
---------------------------------------------------------------------------

    The future year onroad emissions reflect projected changes to fuel 
properties and usage, along with the impact of the rules included in 
MOVES3 for each of the future years. MOVES was run for the years 2023, 
2026, and 2032 to generate the emissions factors relevant to those 
years. Future year activity data for onroad mobile sources were 
provided by some state and local agencies, and otherwise were projected 
to 2023, 2026, and 2032 by first projecting the 2016 activity to year 
2019 based on county level vehicle miles traveled (VMT) from the 
Federal Highway Administration, and then from 2019 to the future years 
using AEO 2021-based factors. The future year emissions were computed 
within SMOKE by multiplying the future year emissions factors developed 
using MOVES with the year-specific activity data.
5. Development of Emissions Inventories for Commercial Marine Vessels
    The commercial marine vessel (CMV) emissions in the 2016 base case 
emissions inventory for this rule were based on those in the 2017 NEI. 
Factors were then applied to adjust the 2017 NEI emissions backward to 
represent emissions for the year 2016. The CMV emissions reflect 
reductions associated with the Emissions Control Area proposal to the 
International Maritime Organization control strategy (EPA-420-F-10-041, 
August 2010); reductions of NOX, VOC, and CO emissions for 
new C3 engines that went into effect in 2011; and fuel sulfur limits 
that went into effect prior to 2016. The cumulative impacts of these 
rules through 2023, 2026 and 2030 \107\ were incorporated into the 
projected emissions for CMV sources. The CMV emissions were split into 
emissions inventories from the larger category 3 (C3) engines, and 
those from the smaller category 1 and 2 (C1C2) engines. CMV emissions 
in California are based on emissions provided by the state. The CMV 
emissions are consistent with the emissions for the 2016v1 platform 
updated CMV emissions released by February 2020 although they include 
future years of 2026 and 2030 instead of 2028.
---------------------------------------------------------------------------

    \107\ CMV emissions were projected out to 2030 instead of 2032 
because that was the last year of data available in a dataset used 
in the projections process. The year 2030 inventories were used in 
the 2032 emissions case.
---------------------------------------------------------------------------

6. Development of Emissions Inventories for Other Nonroad Mobile 
Sources
    Nonroad mobile source emissions inventories (other than CMV, 
locomotive, and aircraft emissions) were developed from monthly, 
county, and process level emissions output from MOVES3. Types of 
nonroad equipment include recreational vehicles, pleasure craft, and 
construction, agricultural, mining, and lawn and garden equipment. 
State-submitted emissions data for nonroad sources were used for 
California.
    The EPA also ran MOVES3 for 2023, 2026, and 2032 to prepare nonroad 
mobile emissions inventories for future years. The nonroad mobile 
emissions control programs include reductions to locomotives, diesel 
engines, and recreational marine engines, along with standards for fuel 
sulfur content and evaporative emissions. A comprehensive list of 
control programs included for mobile sources is available in the 
Emissions Modeling TSD.

[[Page 20066]]

    Line haul locomotives are also considered a type of nonroad mobile 
source but the emissions inventories for locomotives were not developed 
using MOVES3. Year 2016 and 2023 locomotive emissions were developed 
through the 2016v1 process and the year 2016 emissions are mostly 
consistent with those in the 2017 NEI. The projected locomotive 
emissions for 2023, 2026, and 2030 \108\ were developed by applying 
factors to the base year emissions using activity data based on AEO 
freight rail energy use growth rate projections along with emissions 
rates adjusted to account for recent historical trends.
---------------------------------------------------------------------------

    \108\ The farthest out year for which locomotive emissions were 
projected was 2030 and those were used in the 2032 case.
---------------------------------------------------------------------------

7. Development of Emissions Inventories for Nonpoint Sources
    Some emissions for stationary nonpoint sources in the 2016 base 
case emissions inventory come from the 2017 NEI adjusted to 2016 
levels, while others are based on data from the 2014NEIv2 adjusted to 
reflect year 2016 more closely using factors based on changes to human 
population from 2014 to 2016. Stationary nonpoint sources include 
evaporative sources, consumer products, fuel combustion that is not 
captured by point sources, agricultural livestock, agricultural 
fertilizer, residential wood combustion, fugitive dust, and oil and gas 
sources. The emissions sources based on the 2017 NEI include 
agricultural livestock, fugitive dust, residential wood combustion, 
waste disposal (including composting), bulk gasoline terminals, and 
miscellaneous non-industrial sources such as cremation, hospitals, lamp 
breakage, and automotive repair shops. A new method for solvent VOC 
emissions was used.\109\
---------------------------------------------------------------------------

    \109\ https://doi.org/10.5194/acp-21-5079-2021.
---------------------------------------------------------------------------

    Where states provided the Inventory Collaborative information about 
projected control measures or changes in nonpoint source emissions for 
2016v1 or 2016v2, those inputs were incorporated into the projected 
inventories for 2023, 2026, and 2032 to the extent possible. Where 
possible, projection factors based on the AEO were based on AEO 2021. 
Adjustments for state fuel sulfur content rules for fuel oil in the 
Northeast were included. Projected emissions for portable fuel 
containers reflect the impact of projection factors required by the 
final MSAT2 rule and the EISA, including updates to cellulosic ethanol 
plants, ethanol transport working losses, and ethanol distribution 
vapor losses.
    For 2016, nonpoint oil and gas emissions inventories were developed 
based on a run of the 2017 NEI version of the EPA Oil and Gas Tool with 
data for year 2016 coupled with the WRAP inventory for production-
related nonpoint oil and gas emissions in the states of Colorado, 
Montana, New Mexico, North Dakota, South Dakota, Utah, and Wyoming, and 
a California Air Resources Board-provided inventory was used for 
emissions in California. Nonpoint oil and gas emissions in other states 
and exploration-related emissions in the WRAP states were based on a 
run of the 2017 NEI version of the EPA Oil and Gas Tool with input data 
for the year 2016. The 2016 oil and gas inventories were first 
projected to 2019 values based on actual production data, and those 
2019 emissions were projected to 2023, 2026, and 2032 using regional 
projection factors by product type based on AEO 2021 projections. 
NOX and VOC reductions that are co-benefits to the NESHAP 
and NSPS for RICE are reflected for select source categories. In 
addition, Natural Gas Turbines and Process Heaters NSPS NOX 
controls and NSPS Oil and Gas VOC controls are reflected for select 
source categories. The WRAP future year inventory was used in WRAP 
states in all future years.\110\
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    \110\ http://www.wrapair2.org/pdf/WRAP_OGWG_2028_OTB_RevFinalReport_05March2020.pdf.
---------------------------------------------------------------------------

D. Air Quality Modeling To Identify Nonattainment and Maintenance 
Receptors

    In this section, the Agency describes the air quality modeling and 
analyses performed in Step 1 to identify locations where the Agency 
expects there to be nonattainment or maintenance receptors for the 2015 
ozone NAAQS in the 2023, 2026, and 2032 analytic future years. Where 
EPA's analysis shows that an area or site does not fall under the 
definition of a nonattainment or maintenance receptor in 2023, that 
site is excluded from further analysis under EPA's good neighbor 
framework.
    In this proposed rule, the EPA is applying the same approach used 
in the CSAPR Update and the Revised CSAPR Update to identify 
nonattainment and maintenance receptors for the 2008 ozone NAAQS. See 
86 FR 23078-79.
    EPA's approach gives independent effect to both the ``contribute 
significantly to nonattainment'' and the ``interfere with maintenance'' 
prongs of section 110(a)(2)(D)(i)(I), consistent with the D.C. 
Circuit's direction in North Carolina.\111\ Further, in its decision on 
the remand of the CSAPR from the Supreme Court in the EME Homer City 
case, the D.C. Circuit confirmed that EPA's approach to identifying 
maintenance receptors in the CSAPR comported with the court's prior 
instruction to give independent meaning to the ``interfere with 
maintenance'' prong in the good neighbor provision. EME Homer City II, 
795 F.3d at 136.
---------------------------------------------------------------------------

    \111\ 531 F.3d at 910-911 (holding that the EPA must give 
``independent significance'' to each prong of CAA section 
110(a)(2)(D)(i)(I)).
---------------------------------------------------------------------------

    In the CSAPR Update and the Revised CSAPR Update, the EPA 
identified nonattainment receptors as those monitoring sites that are 
projected to have average design values that exceed the NAAQS and that 
are also measuring nonattainment based on the most recent monitored 
design values. This approach is consistent with prior transport 
rulemakings, such as the NOX SIP Call and CAIR, where the 
EPA defined nonattainment receptors as those areas that both currently 
monitor nonattainment and that the EPA projects will be in 
nonattainment in the future compliance year.\112\
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    \112\ See 63 FR 57375, 57377 (October 27, 1998); 70 FR 
25241(January 14, 2005). See also North Carolina, 531 F.3d at 913-
914 (affirming as reasonable EPA's approach to defining 
nonattainment in CAIR).
---------------------------------------------------------------------------

    The Agency explained in the NOX SIP Call and CAIR and 
then reaffirmed in the CSAPR Update that the EPA has the most 
confidence in our projections of nonattainment for those counties that 
also measure nonattainment for the most recent period of available 
ambient data. The EPA separately identified maintenance receptors as 
those receptors that would have difficulty maintaining the relevant 
NAAQS in a scenario that accounts for historical variability in air 
quality at that receptor. The variability in air quality was determined 
by evaluating the ``maximum'' future design value at each receptor 
based on a projection of the maximum measured design value over the 
relevant period. The EPA interprets the projected maximum future design 
value to be a potential future air quality outcome consistent with the 
meteorology that yielded maximum measured concentrations in the ambient 
data set analyzed for that receptor (i.e., ozone conducive 
meteorology). The EPA also recognizes that previously experienced 
meteorological conditions (e.g., dominant wind direction, temperatures, 
and air mass patterns) promoting ozone formation that led to maximum 
concentrations in the measured data may reoccur in the

[[Page 20067]]

future. The maximum design value gives a reasonable projection of 
future air quality at the receptor under a scenario in which such 
conditions do, in fact, reoccur.\113\ The projected maximum design 
value is used to identify upwind emissions that, under those 
circumstances, could interfere with the downwind area's ability to 
maintain the NAAQS.
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    \113\ The EPA's air quality modeling guidance identifies the use 
of the highest of the relevant base period design values as a means 
to evaluate future year attainment under meteorological conditions 
that are especially conducive to ozone formation. See U.S. 
Environmental Protection Agency, 2018. Modeling Guidance for 
Demonstrating Attainment of Air Quality Goals for Ozone, 
PM2.5, and Regional Haze, Research Triangle Park, NC.
---------------------------------------------------------------------------

    Therefore, applying this methodology in this proposed rule, EPA 
assessed the magnitude of the maximum projected design values for 2023, 
2026, and 2032 at each receptor in relation to the 2015 ozone NAAQS 
and, where such a value exceeds the NAAQS, the EPA determined that 
receptor to be a ``maintenance'' receptor for purposes of defining 
interference with maintenance, consistent with the method used in CSAPR 
and upheld by the D.C. Circuit in EME Homer City II.\114\ That is, 
monitoring sites with a maximum design value that exceeds the NAAQS are 
projected to have maintenance problems in the future analytic 
years.\115\
---------------------------------------------------------------------------

    \114\ See 795 F.3d at 136.
    \115\ The EPA issued a memorandum in October 2018, providing 
additional information to states developing interstate transport SIP 
submissions for the 2015 8-hour ozone NAAQS concerning 
considerations for identifying downwind areas that may have problems 
maintaining the standard at Step 1 of the 4-step interstate 
transport framework. See Considerations for Identifying Maintenance 
Receptors for Use in Clean Air Act Section 110(a)(2)(D)(i)(I) 
Interstate Transport State Implementation Plan Submissions for the 
2015 Ozone National Ambient Air Quality Standards, October 19, 2018 
(``October 2018 memorandum''), available in Docket No. EPA-HQ-OAR-
2021-0663 or at https://www.epa.gov/airmarkets/memo-and-supplemental-information-regarding-interstate-transport-sips-2015-ozone-naaqs. The EPA does not propose to adopt the information or 
suggested analytical approaches in that memorandum in this proposed 
rule proposing FIPs. Potential alternative approaches would 
introduce unnecessary and substantial additional analytical burdens 
that could frustrate timely and efficient implementation of good 
neighbor obligations. In addition, the information supplied in that 
memorandum is now outdated due to several additional years of air 
quality monitoring data and updated modeling results. EPA's current 
approach to defining ``maintenance'' receptors has been upheld and 
continues to provide an appropriate approach to addressing the 
``interference with maintenance'' prong of the Good Neighbor 
provision. See EME Homer City, 795 F.3d 118, 136-37; Wisconsin, 938 
F.3d at 325-26.
---------------------------------------------------------------------------

    Recognizing that nonattainment receptors are also, by definition, 
maintenance receptors, the EPA often uses the term ``maintenance-only'' 
to refer to receptors that are not also nonattainment receptors. 
Consistent with the concepts for maintenance receptors, as described 
above, the EPA identifies ``maintenance-only'' receptors as those 
monitoring sites that have projected average design values above the 
level of the applicable NAAQS, but that are not currently measuring 
nonattainment based on the most recent official design values. In 
addition, those monitoring sites with projected average design values 
below the NAAQS, but with projected maximum design values above the 
NAAQS are also identified as ``maintenance only'' receptors, even if 
they are currently measuring nonattainment based on the most recent 
official design values.
    Consistent with EPA's modeling guidance, the 2016 base year and 
future year air quality modeling results were used in a relative sense 
to project design values for 2023, 2026, and 2032. That is, the ratios 
of future year model predictions to base year model predictions are 
used to adjust ambient ozone design values \116\ up or down depending 
on the relative (percent) change in model predictions for each 
location. The modeling guidance recommends using measured ozone 
concentrations for the 5-year period centered on the base year as the 
air quality data starting point for future year projections. This 
average design value is used to dampen the effects of inter-annual 
variability in meteorology on ozone concentrations and to provide a 
reasonable projection of future air quality at the receptor under 
average conditions. In addition, the Agency calculated maximum design 
values from within the 5-year base period to represent conditions when 
meteorology is more favorable than average for ozone formation. Because 
the base year for the air quality modeling used in this proposed rule 
is 2016, measured data for 2014-2018 (i.e., design values for 2016, 
2017, and 2018) were used in order to project average and maximum 
design values in 2023, 2026, and 2032.
---------------------------------------------------------------------------

    \116\ The ozone design value at a particular monitoring site is 
the 3-year average of the annual 4th highest daily maximum 8-hour 
ozone concentration at that site.
---------------------------------------------------------------------------

    The ozone predictions from the 2016 and future year air quality 
model simulations were used to project 2016-2018 average and maximum 
ozone design values to 2023, 2026, and 2032 using an approach similar 
to the approach in EPA's guidance for attainment demonstration 
modeling. This guidance recommends using model predictions from the 3 x 
3 array of grid cells \117\ surrounding the location of the monitoring 
site to calculate a Relative Response Factor (RRF) for that site.\118\ 
The 2016-2018 base period average and maximum design values were 
multiplied by the RRF to project each of these design values to each of 
the three future years. In this manner, the projected design values are 
grounded in monitored data, and not the absolute model-predicted future 
year concentrations. Following the approach in the CSAPR Update and the 
Revised CSAPR Update, the EPA also projected future year design values 
based on a modified version of the ``3 x 3'' approach for those 
monitoring sites located in coastal areas. In this alternative 
approach, EPA eliminated from the RRF calculations the modeling data in 
those grid cells that are dominated by water (i.e., more than 50 
percent of the area in the grid cell is water) and that do not contain 
a monitoring site (i.e., if a grid cell is more than 50 percent water 
but contains an air quality monitor, that cell would remain in the 
calculation). The choice of more than 50 percent of the grid cell area 
as water as the criteria for identifying overwater grid cells is based 
on the treatment of land use in the Weather Research and Forecasting 
model (WRF).\119\ Specifically, in the WRF meteorological model those 
grid cells that are greater than 50% overwater are treated as being 100 
percent overwater. In such cases the meteorological conditions in the 
entire grid cell reflect the vertical mixing and winds over water, even 
if part of the grid cell also happens to be over land with land-based 
emissions, as can often be the case for coastal areas. Overlaying land-
based emissions with overwater meteorology may be representative of 
conditions at coastal monitors during times of on-shore flow associated 
with synoptic conditions or sea-breeze or lake-breeze wind flows. But 
there may be other times, particularly with off-shore wind flow, when 
vertical mixing of land-based emissions may be too

[[Page 20068]]

limited due to the presence of overwater meteorology. Thus, for our 
modeling EPA projected average and maximum design values at individual 
monitoring sites based on both the ``3 x 3'' approach as well as the 
alternative approach that eliminates overwater cells in the RRF 
calculation for near-coastal areas (i.e., ``no water'' approach). The 
projected 2023, 2026, and 2032 design values using both the ``3 x 3'' 
and ``no-water'' approaches are provided in the docket for this 
proposed rule. For this proposed rule, the EPA is relying upon design 
values based on the ``no water'' approach for identifying nonattainment 
and maintenance receptors.\120\
---------------------------------------------------------------------------

    \117\ As noted above, each model grid cell is 12 x 12 km.
    \118\ The relative response factor represents the change in 
ozone at a given site. In order to calculate the RRF, EPA's modeling 
guidance recommends selecting the 10 highest ozone days in an ozone 
season at a given monitor in the base year, noting which of the grid 
cells surrounding the monitor experienced the highest ozone 
concentrations in the base year, and averaging those ten highest 
concentrations. The model is then run using the projected year 
emissions, in this case 2023, with all other model variables held 
constant. Ozone concentrations from the same ten days, in the same 
grid cells, are then averaged. The fractional change between the 
base year (2016 model run) averaged ozone concentrations and the 
future year (e.g., 2023 model run) averaged ozone concentrations 
represents the relative response factor.
    \119\ https://www.mmm.ucar.edu/weather-research-and-forecasting-model.
    \120\ Using design values from the ``3 x 3'' approach, the 
maintenance-only receptor at site 170317002 in Cook County, IL would 
become a nonattainment receptor because the average design value 
with the ``3 x 3'' approach is 71.1 ppb versus 70.1 ppb with the 
``no water'' approach. In addition, the monitor at site 170971007 in 
Lake County, IL which was not projected to be a receptor using the 
``no water'' approach would be a maintenance-only receptor with the 
``3 x 3'' approach because the maximum design value with the ``no 
water'' approach was 69.9 ppb versus a maximum design value of 71.2 
ppb with the ``3 x 3'' approach. However, including this Lake 
County, Illinois site as a receptor would not affect which states 
are covered by this proposed rule.
---------------------------------------------------------------------------

    Consistent with the truncation and rounding procedures for the 8-
hour ozone NAAQS, the projected design values are truncated to integers 
in units of ppb.\121\ Therefore, projected design values that are 
greater than or equal to 71 ppb are considered to be violating the 2015 
ozone NAAQS. For those sites that are projected to be violating the 
NAAQS based on the average design values in the future analytic years, 
the Agency examined the measured design values for 2020, which are the 
most recent official measured design values at the time of this 
proposal. As noted earlier, the Agency proposes to identify 
nonattainment receptors in this rulemaking as those sites that are 
violating the NAAQS based on current measured air quality and also have 
projected average design values of 71 ppb or greater. Maintenance-only 
receptors include both (1) those sites with projected average design 
values above the NAAQS that are currently measuring clean data and (2) 
those sites with projected average design values below the level of the 
NAAQS, but with projected maximum design values of 71 ppb or greater. 
In addition to the maintenance-only receptors, the 2021 ozone 
nonattainment receptors are also maintenance receptors because the 
maximum design values for each of these sites is always greater than or 
equal to the average design value. The monitoring sites that the Agency 
projects to be nonattainment and maintenance receptors for the ozone 
NAAQS in the 2023 and 2026 base case are used for assessing the 
contribution of emissions in upwind states to downwind nonattainment 
and maintenance of ozone NAAQS as part of this proposal.
---------------------------------------------------------------------------

    \121\ 40 CFR part 50, Appendix P to Part 50--Interpretation of 
the Primary and Secondary National Ambient Air Quality Standards for 
Ozone.
---------------------------------------------------------------------------

    Table V.D-1 contains the 2016-centered \122\ base period average 
and maximum 8-hour ozone design values, the 2023 base case average and 
maximum design values and the 2020 design values for the sites that are 
projected to be nonattainment receptors in 2023. Table V.D-2 contains 
this same information for monitoring sites that are projected to be 
maintenance-only receptors in 2023. The design values for all 
monitoring sites in the U.S. are provided in the docket for this rule. 
Additional details on the approach for projecting average and maximum 
design values are provided in the AQM TSD.
---------------------------------------------------------------------------

    \122\ 2016-centered averaged design values represent the average 
of the design values for 2016, 2017, and 2018. Similarly, the 
maximum 2016-centered design value is the highest measured design 
value from these three design value periods.

  Table V.D-1--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2020 Design Values (ppb) at Projected Nonattainment
                                                                       Receptors *
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           2016 centered   2016 centered
             Monitor ID                  State             County             average         maximum      2023 average    2023 maximum        2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
060170010..........................  CA            El Dorado............            85.3              88            76.3            78.7              84
060170020..........................  CA            El Dorado............            82.0              84            74.3            76.2              80
060190007..........................  CA            Fresno...............            87.0              89            80.4            82.2              80
060190011..........................  CA            Fresno...............            90.0              91            82.9            83.8              84
060190242..........................  CA            Fresno...............            84.3              86            79.5            81.1              79
060194001..........................  CA            Fresno...............            90.3              92            82.8            84.4              81
060195001..........................  CA            Fresno...............            91.0              94            83.7            86.4              84
060250005..........................  CA            Imperial.............            76.7              77            76.3            76.6              78
060251003..........................  CA            Imperial.............            76.0              76            75.4            75.4              68
060290007..........................  CA            Kern.................            87.7              89            82.8            84.0              93
060290008..........................  CA            Kern.................            83.0              85            79.1            81.0              85
060290011..........................  CA            Kern.................            83.3              85            78.8            80.4              86
060290014..........................  CA            Kern.................            86.0              88            81.3            83.2              85
060290232..........................  CA            Kern.................            79.3              82            74.9            77.5              83
060292012..........................  CA            Kern.................            89.3              90            84.1            84.7              85
060295002..........................  CA            Kern.................            87.3              89            82.4            84.0              89
060296001..........................  CA            Kern.................            80.7              81            77.1            77.4              82
060311004..........................  CA            Kings................            83.3              84            76.9            77.6              80
060370002..........................  CA            Los Angeles..........            94.3              99            88.0            92.4              97
060370016..........................  CA            Los Angeles..........           100.0             103            93.4            96.2             107
060371201..........................  CA            Los Angeles..........            88.3              91            82.7            85.3              92
060371602..........................  CA            Los Angeles..........            75.7              76            73.6            73.9              78
060371701..........................  CA            Los Angeles..........            92.0              95            85.6            88.4              88
060372005..........................  CA            Los Angeles..........            84.7              86            80.7            81.9              93
060376012..........................  CA            Los Angeles..........            98.0             100            91.6            93.4             101
060379033..........................  CA            Los Angeles..........            87.3              89            80.7            82.2              80
060390004..........................  CA            Madera...............            80.3              83            75.7            78.3              76
060392010..........................  CA            Madera...............            82.7              84            77.0            78.2              78
060430003..........................  CA            Mariposa.............            76.0              79            74.2            77.1              79
060470003..........................  CA            Merced...............            80.7              82            74.7            75.9              76
060570005..........................  CA            Nevada...............            86.3              90            78.1            81.5              82

[[Page 20069]]

 
060592022..........................  CA            Orange...............            77.7              78            72.5            72.8              82
060595001..........................  CA            Orange...............            75.3              76            72.3            73.0              77
060610003..........................  CA            Placer...............            85.0              88            77.1            79.8             N/A
060610004..........................  CA            Placer...............            79.3              85            71.9            77.0             N/A
060610006..........................  CA            Placer...............            80.0              81            72.8            73.7              72
060650008..........................  CA            Riverside............            76.5              79            71.0            73.3             N/A
060650012..........................  CA            Riverside............            95.3              98            85.9            88.3              99
060650016..........................  CA            Riverside............            79.0              80            72.0            72.9              78
060651016..........................  CA            Riverside............            99.7             101            89.8            90.9              99
060652002..........................  CA            Riverside............            82.7              85            76.4            78.5              84
060655001..........................  CA            Riverside............            88.7              91            80.5            82.6              88
060656001..........................  CA            Riverside............            92.3              93            83.5            84.1              94
060658001..........................  CA            Riverside............            96.7              98            89.5            90.7              96
060658005..........................  CA            Riverside............            95.0              98            87.9            90.7              98
060659001..........................  CA            Riverside............            88.7              91            80.8            82.9              87
060670002..........................  CA            Sacramento...........            77.7              78            71.4            71.7              72
060670012..........................  CA            Sacramento...........            82.3              83            74.8            75.4             N/A
060710001..........................  CA            San Bernardino.......            79.0              80            74.5            75.4              81
060710005..........................  CA            San Bernardino.......           110.3             112           100.3           101.8             109
060710012..........................  CA            San Bernardino.......            95.0              98            87.3            90.1              90
060710306..........................  CA            San Bernardino.......            84.0              86            76.8            78.6              83
060711004..........................  CA            San Bernardino.......           105.7             109            97.2           100.2             106
060712002..........................  CA            San Bernardino.......            97.7              99            90.1            91.3             102
060714001..........................  CA            San Bernardino.......            90.3              91            82.6            83.3              87
060714003..........................  CA            San Bernardino.......           104.0             107            95.2            98.0             114
060719002..........................  CA            San Bernardino.......            87.3              89            80.1            81.6              86
060719004..........................  CA            San Bernardino.......           108.7             111            99.5           101.6             110
060731006..........................  CA            San Diego............            83.0              84            76.9            77.9              79
060773005..........................  CA            San Joaquin..........            77.3              79            71.3            72.8              70
060990005..........................  CA            Stanislaus...........            81.0              82            75.4            76.3              79
060990006..........................  CA            Stanislaus...........            83.7              84            77.5            77.8              80
061030004..........................  CA            Tehama...............            79.7              81            72.3            73.4              74
061070006..........................  CA            Tulare...............            84.7              86            79.1            80.3              83
061070009..........................  CA            Tulare...............            89.0              89            82.6            82.6              88
061072002..........................  CA            Tulare...............            82.7              85            75.5            77.6              83
061072010..........................  CA            Tulare...............            84.0              86            77.0            78.8              80
061090005..........................  CA            Tuolumne.............            80.7              83            75.6            77.8              77
080350004..........................  CO            Douglas..............            77.3              78            71.7            72.3              81
080590006..........................  CO            Jefferson............            77.3              78            72.6            73.3              79
080590011..........................  CO            Jefferson............            79.3              80            73.8            74.4              80
080690011..........................  CO            Larimer..............            75.7              77            71.3            72.6              75
090010017..........................  CT            Fairfield............            79.3              80            73.0            73.7              82
090013007..........................  CT            Fairfield............            82.0              83            74.2            75.1              80
090019003..........................  CT            Fairfield............            82.7              83            76.1            76.4              79
090099002..........................  CT            New Haven............            79.7              82            71.8            73.9              80
481671034..........................  TX            Galveston............            75.7              77            71.1            72.3              74
482010024..........................  TX            Harris...............            79.3              81            75.2            76.8              79
482010055..........................  TX            Harris...............            76.0              77            71.0            72.0              76
490110004..........................  UT            Davis................            75.7              78            72.9            75.1              77
490353006..........................  UT            Salt Lake............            76.3              78            73.6            75.3              74
490353013..........................  UT            Salt Lake............            76.5              77            74.4            74.9              73
550590019..........................  WI            Kenosha..............            78.0              79            72.8            73.7              74
551010020..........................  WI            Racine...............            76.0              78            71.3            73.2              73
551170006..........................  WI            Sheboygan............            80.0              81            73.6            74.5              75
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ``N/A'' is used to denote that there is no valid 2020 design value.


 Table V.D-2--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2020 Design Values (ppb) at Projected Maintenance-Only
                                                                        Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           2016 centered   2016 centered
             Monitor ID                  State             County             average         maximum      2023 average    2023 maximum        2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
040278011..........................  AZ            Yuma.................            72.3              74            70.5            72.2              68
060070007..........................  CA            Butte................            76.7              79            68.9            71.0              73
060090001..........................  CA            Calaveras............            77.0              78            70.9            71.9              72
060371103..........................  CA            Los Angeles..........            73.0              74            70.5            71.5              76
060430006..........................  CA            Mariposa.............            75.0              76            70.1            71.0              79

[[Page 20070]]

 
060675003..........................  CA            Sacramento...........            77.3              79            70.2            71.7              70
060711234..........................  CA            San Bernardino.......            72.3              76            70.6            74.2              76
061112002..........................  CA            Ventura..............            77.3              78            70.9            71.6              77
170310001..........................  IL            Cook.................            73.0              77            69.6            73.4              75
170310032..........................  IL            Cook.................            72.3              75            69.8            72.4              74
170310076..........................  IL            Cook.................            72.0              75            69.3            72.1              69
170314201..........................  IL            Cook.................            73.3              77            69.9            73.4              77
170317002..........................  IL            Cook.................            74.0              77            70.1            73.0              75
320030075..........................  NV            Clark................            75.0              76            70.0            71.0              74
350130021..........................  NM            Dona Ana.............            72.7              74            70.9            72.2              78
350130022..........................  NM            Dona Ana.............            71.3              74            69.5            72.1              74
420170012..........................  PA            Bucks................            79.3              81            70.7            72.2              74
480391004..........................  TX            Brazoria.............            74.7              77            70.1            72.3              73
481210034..........................  TX            Denton...............            78.0              80            70.4            72.2              72
481410037..........................  TX            El Paso..............            71.3              73            69.6            71.3              76
482011034..........................  TX            Harris...............            73.7              75            70.3            71.6              73
482011035..........................  TX            Harris...............            71.3              75            68.0            71.6              70
490450004..........................  UT            Tooele...............            73.5              74            70.8            71.3              69
490570002..........................  UT            Weber................            73.0              75            70.6            72.5             N/A
490571003..........................  UT            Weber................            73.0              74            70.5            71.5              71
550590025..........................  WI            Kenosha..............            73.7              77            69.2            72.3              74
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In total, in the 2023 base case there are a total of 111 receptors 
nationwide including 85 nonattainment receptors and 26 maintenance-only 
receptors.\123\ Of the 85 nonattainment receptors in 2023, 75 remain 
nonattainment receptors while 8 are projected to become maintenance-
only receptors and 2 are projected to be in attainment in 2026. Of the 
26 maintenance-only receptors in 2023, 13 are projected to remain 
maintenance-only receptors and 13 are projected to be in attainment in 
2026. The projected average and maximum design values in 2026 for all 
receptors are included in the AQM TSD.
---------------------------------------------------------------------------

    \123\ The EPA's modeling also projects that three monitoring 
sites in the Uintah Basin (i.e., monitor 490472003 in Uintah County, 
Utah and monitors 490130002 and 490137011 in Duchesne County, Utah) 
will have average design values above the NAAQS in 2023. However, as 
described in the AQM TSD, the Uinta Basin nonattainment area was 
designated as nonattainment for the 2015 ozone NAAQS not because of 
an ongoing problem with summertime ozone (as is usually the case in 
other parts of the country), but instead because it violates the 
ozone NAAQS in winter. The main causes of the Uinta Basin's 
wintertime ozone are sources located at low elevations within the 
Basin, the Basin's unique topography, and the influence of the 
wintertime meteorologic inversions that keep ozone and ozone 
precursors near the Basin floor and restrict air flow in the Basin. 
Because of the localized nature of the ozone problem at these sites 
the EPA has not identified these three monitors as receptors in Step 
1 of this proposed rule.
---------------------------------------------------------------------------

E. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions
    This section documents the procedures the EPA used to quantify the 
impact of emissions from specific upwind states on ozone design values 
in 2023 and 2026 for the identified downwind nonattainment and 
maintenance receptors. The EPA used CAMx photochemical source 
apportionment modeling to quantify the impact of emissions in specific 
upwind states on downwind nonattainment and maintenance receptors for 
8-hour ozone. CAMx employs enhanced source apportionment techniques 
that track the formation and transport of ozone from specific emissions 
sources and calculates the contribution of sources and precursors to 
ozone for individual receptor locations. The benefit of the 
photochemical model source apportionment technique is that all modeled 
ozone at a given receptor location in the modeling domain is tracked 
back to specific sources of emissions and boundary conditions to fully 
characterize culpable sources.
    The EPA performed nationwide, state-level ozone source 
apportionment modeling using the CAMx Ozone Source Apportionment 
Technology/Anthropogenic Precursor Culpability Analysis (OSAT/APCA) 
technique \124\ to quantify the contribution of 2023 and 2026 base case 
NOX and VOC emissions from all sources in each state to the 
corresponding projected ozone design values in 2023 and 2026 at air 
quality monitoring sites. The CAMx OSAT/APCA model run was performed 
for the period May 1 through September 30 using the projected future 
base case emissions and 2016 meteorology for this time period. As 
described earlier, in the source apportionment modeling the Agency 
tracked (i.e., tagged) the amount of ozone formed from anthropogenic 
emissions in each state individually as well as the contributions from 
other sources (e.g., natural emissions).
---------------------------------------------------------------------------

    \124\ As part of this technique, ozone formed from reactions 
between biogenic VOC and NOX with anthropogenic 
NOX and VOC are assigned to the anthropogenic emissions.
---------------------------------------------------------------------------

    In the state-by-state source apportionment model run, the EPA 
tracked the ozone formed from each of the following tags:
     States--anthropogenic NOX and VOC emissions 
from each state tracked individually (emissions from all anthropogenic 
sectors in a given state were combined);
     Biogenics--biogenic NOX and VOC emissions 
domain-wide (i.e., not by state);
     Boundary Concentrations--concentrations transported into 
the air quality modeling domain;
     Tribes--the emissions from those tribal lands for which 
the Agency has point source inventory data in the 2016v1 emissions 
modeling platform (EPA did not model the contributions from individual 
tribes);

[[Page 20071]]

     Canada and Mexico--anthropogenic emissions from sources in 
the portions of Canada and Mexico included in the modeling domain (the 
EPA did not model the contributions from Canada and Mexico separately);
     Fires--combined emissions from wild and prescribed fires 
domain-wide (i.e., not by state); and
     Offshore--combined emissions from offshore marine vessels 
and offshore drilling platforms.

The contribution modeling provided contributions to ozone from 
anthropogenic NOX and VOC emissions in each state, 
individually. The contributions to ozone from chemical reactions 
between biogenic NOX and VOC emissions were modeled and 
assigned to the ``biogenic'' category. The contributions from wildfire 
and prescribed fire NOX and VOC emissions were modeled and 
assigned to the ``fires'' category. That is, the contributions from the 
``biogenic'' and ``fires'' categories are not assigned to individual 
states nor are they included in the state contributions.
    For the Step 2 analysis, the EPA calculated a contribution metric 
that considers the average contribution on the 10 highest ozone 
concentration days (i.e., top 10 days) in 2023. This average 
contribution metric is intended to provide a reasonable representation 
of the contribution from individual states to projected future year 
design values, based on modeled transport patterns and other 
meteorological conditions generally associated with modeled high ozone 
concentrations at the receptor. An average contribution metric 
constructed in this manner is beneficial since the magnitude of the 
contributions is directly related to the magnitude of the design value 
at each site.
    The analytic steps for calculating the contribution metric for the 
2023 analytic year are as follows:
    (1) Calculate the 8-hour average contribution from each source tag 
to each monitoring site for the time period of the 8-hour daily maximum 
modeled concentrations in 2023;
    (2) Average the contributions and average the concentrations for 
the top 10 modeled ozone concentration days in 2023;
    (3) Divide the average contribution by the corresponding average 
concentration to obtain a Relative Contribution Factor (RCF) for each 
monitoring site;
    (4) Multiply the 2023 average design values by the 2023 RCF at each 
site to produce the average contribution metric values in 2023.\125\
---------------------------------------------------------------------------

    \125\ Note that a contribution metric value was not calculated 
for any receptor at which there were fewer than 5 days with model-
predicted MDA8 ozone concentrations greater than or equal to 60 ppb 
in 2023. See the AQM TSD for information on those receptors that did 
not meet this criterion.
---------------------------------------------------------------------------

    This same approach was applied to calculate contribution metric 
values at individual monitoring sites for 2026.\126\
---------------------------------------------------------------------------

    \126\ In order to provide consistency in the contributions for 
2023 and 2026, the contribution metric values for 2026 are based on 
the 2026 daily contributions for the same days that were used to 
calculate the contribution metric values for 2023.
---------------------------------------------------------------------------

    The resulting contributions from each tag to each monitoring site 
in the U.S. for 2023 and 2026 can be found in the docket for this 
proposed rule. Additional details on the source apportionment modeling 
and the procedures for calculating contributions can be found in the 
AQM TSD.
    The largest contribution from each state that is the subject of 
this rule to 8-hour ozone nonattainment and maintenance receptors in 
downwind states in 2023 and 2026 are provided in Table V.E.1-1 and 
Table V.E.1-2, respectively.

      Table V.E.1-1--Largest Contribution to Downwind 8-Hour Ozone
          Nonattainment and Maintenance Receptors in 2023 (ppb)
------------------------------------------------------------------------
                                                              Largest
                                              Largest      contribution
                                           contribution     to downwind
              Upwind state                  to downwind    maintenance-
                                           nonattainment       only
                                             receptors       receptors
------------------------------------------------------------------------
Alabama.................................            0.88            0.71
Arizona.................................            0.40            0.21
Arkansas................................            1.00            1.39
California..............................           34.24            7.44
Colorado................................            0.07            0.20
Connecticut.............................            0.01            0.21
Delaware................................            0.53            1.36
District of Columbia....................            0.04            0.07
Florida.................................            0.16            0.15
Georgia.................................            0.16            0.17
Idaho...................................            0.55            0.57
Illinois................................           18.13           18.55
Indiana.................................            6.60            7.10
Iowa....................................            0.64            0.58
Kansas..................................            0.42            0.59
Kentucky................................            0.83            0.88
Louisiana...............................            5.39            7.03
Maine...................................            0.01            0.01
Maryland................................            1.29            2.40
Massachusetts...........................            0.30            0.30
Michigan................................            1.27            1.67
Minnesota...............................            0.50            0.97
Mississippi.............................            1.04            1.14
Missouri................................            1.08            1.66
Montana.................................            0.08            0.11
Nebraska................................            0.26            0.36
Nevada..................................            0.89            0.58
New Hampshire...........................            0.10            0.06
New Jersey..............................            8.85            5.79

[[Page 20072]]

 
New Mexico..............................            0.30            0.13
New York................................           16.81            1.80
North Carolina..........................            0.61            0.33
North Dakota............................            0.12            0.37
Ohio....................................            1.94            1.88
Oklahoma................................            0.57            1.19
Oregon..................................            1.10            1.31
Pennsylvania............................            6.90            0.51
Rhode Island............................            0.04            0.04
South Carolina..........................            0.19            0.07
South Dakota............................            0.05            0.09
Tennessee...............................            0.60            0.94
Texas...................................            1.72            1.81
Utah....................................            1.37            0.10
Vermont.................................            0.02            0.02
Virginia................................            1.77            1.63
Washington..............................            0.34            0.40
West Virginia...........................            1.45            1.44
Wisconsin...............................            0.19            2.61
Wyoming.................................            0.81            0.19
------------------------------------------------------------------------


      Table V.E.1-2--Largest Contribution to Downwind 8-Hour Ozone
          Nonattainment and Maintenance Receptors in 2026 (ppb)
------------------------------------------------------------------------
                                                              Largest
                                              Largest      contribution
                                           contribution     to downwind
              Upwind state                  to downwind    maintenance-
                                           nonattainment       only
                                             receptors       receptors
------------------------------------------------------------------------
Alabama.................................            0.17            0.48
Arizona.................................            0.35            0.23
Arkansas................................            0.62            1.30
California..............................           33.45            4.85
Colorado................................            0.05            0.08
Connecticut.............................            0.01            0.01
Delaware................................            0.42            0.52
District of Columbia....................            0.03            0.04
Florida.................................            0.10            0.09
Georgia.................................            0.14            0.16
Idaho...................................            0.48            0.48
Illinois................................           17.81           18.14
Indiana.................................            6.43            6.99
Iowa....................................            0.57            0.57
Kansas..................................            0.40            0.57
Kentucky................................            0.80            0.80
Louisiana...............................            4.25            6.97
Maine...................................            0.01            0.01
Maryland................................            1.11            1.23
Massachusetts...........................            0.29            0.14
Michigan................................            1.03            1.58
Minnesota...............................            0.36            0.91
Mississippi.............................            0.36            0.90
Missouri................................            0.98            1.53
Montana.................................            0.07            0.08
Nebraska................................            0.11            0.23
Nevada..................................            0.81            0.51
New Hampshire...........................            0.09            0.02
New Jersey..............................            8.54            5.47
New Mexico..............................            0.29            0.23
New York................................           16.58           11.29
North Carolina..........................            0.38            0.54
North Dakota............................            0.11            0.34
Ohio....................................            1.78            1.83
Oklahoma................................            0.54            0.72

[[Page 20073]]

 
Oregon..................................            0.98            0.88
Pennsylvania............................            6.82            4.74
Rhode Island............................            0.04            0.01
South Carolina..........................            0.15            0.17
South Dakota............................            0.03            0.06
Tennessee...............................            0.25            0.34
Texas...................................            1.61            1.70
Utah....................................            0.95            1.18
Vermont.................................            0.02            0.01
Virginia................................            1.14            1.68
Washington..............................            0.31            0.28
West Virginia...........................            1.23            1.35
Wisconsin...............................            0.15            2.44
Wyoming.................................            0.46            0.80
------------------------------------------------------------------------

2. Application of Contribution Screening Threshold
    The EPA evaluated the magnitude of the contributions from each 
upwind state to downwind nonattainment and maintenance receptors. In 
Step 2 of the interstate transport framework, the EPA uses an air 
quality screening threshold to identify upwind states that contribute 
to downwind ozone concentrations in amounts sufficient to ``link'' them 
to these to downwind nonattainment and maintenance receptors. The 
contributions from each state to each downwind nonattainment or 
maintenance receptor that were used for the Step 2 evaluation can be 
found in the AQM TSD.
    The EPA proposes to apply an air quality screening threshold of 1 
percent of the NAAQS, as it has used since the CSAPR rulemaking, 
including in the CSAPR Update, the Revised CSAPR Update, and numerous 
actions evaluating states' transport SIP submittals. EPA continues to 
observe that the majority of nonattainment and maintenance receptors 
identified at Step 1 are impacted collectively by contributions of 
ozone transport from numerous upwind states. Therefore, application of 
a uniform screening threshold allows EPA to identify upwind states that 
share a responsibility under the interstate transport provision to 
eliminate their significant contribution.
    The EPA recognizes that in 2018 it issued a memorandum indicating 
the potential for states to use a higher threshold at Step 2 in the 
development of their good neighbor SIP submissions where it could be 
technically justified. The August 2018 memorandum stated that ``it may 
be reasonable and appropriate'' for states to rely on an alternative 1 
ppb threshold at Step 2.\127\ (The memorandum also indicated that any 
higher alternative threshold, such as 2 ppb, would likely not be 
appropriate.) Here, the EPA proposes to fulfill its role under CAA 
section 110(c) in promulgating FIPs to directly implement good neighbor 
requirements, and in this role, the EPA notes that it is authorized to 
exercise discretion in making policy determinations such as the 
appropriateness of a particular contribution threshold that would 
otherwise have been exercised by states. Further, as the EPA has 
explained in several notices proposing transport SIP disapprovals, see, 
e.g., 87 FR 9498 and 87 FR 9510 (Feb. 22, 2022), its experience since 
the issuance of the August 2018 memorandum regarding use of alternative 
thresholds leads the Agency to now believe it may not be appropriate to 
continue to attempt to recognize alternative contribution thresholds at 
Step 2, either in the context of SIPs or FIPs.
---------------------------------------------------------------------------

    \127\ August 2018 memo at 4.
---------------------------------------------------------------------------

    EPA's experience since 2018 is that allowing for alternative Step 2 
thresholds may be impractical or otherwise inadvisable for a number of 
additional policy reasons. For a regional air pollutant such as ozone, 
consistency in requirements and expectations across all states is 
essential. In the context of a FIP proposal (as much as in the context 
of SIP actions), the Agency now believes using different thresholds at 
Step 2 with respect to the 2015 ozone NAAQS raises substantial policy 
consistency and practical implementation concerns.\128\ The 
availability of different thresholds at Step 2 has the potential to 
result in inconsistent application of good neighbor obligations. From 
the perspective of ensuring effective regional implementation of good 
neighbor obligations, the more important analysis is the evaluation of 
the emissions reductions needed, if any, to address a state's 
significant contribution after consideration of a multifactor analysis 
at Step 3, including a detailed evaluation that considers air quality 
factors and cost. Where alternative thresholds for purposes of Step 2 
may be ``similar'' in terms of capturing the relative amount of upwind 
contribution (as described in the August 2018 memorandum), nonetheless, 
use of an alternative threshold would allow certain states to avoid 
further evaluation of potential emissions controls while other states 
must proceed to a Step 3 analysis. This can create significant equity 
and consistency problems among states.
---------------------------------------------------------------------------

    \128\ We note that Congress has placed on the EPA a general 
obligation to ensure the requirements of the CAA are implemented 
consistently across states and regions. See CAA section 301(a)(2). 
Where the management and regulation of interstate pollution levels 
spanning many states is at stake, consistency in application of CAA 
requirements is paramount.
---------------------------------------------------------------------------

    More importantly, in promulgating FIPs to address these obligations 
on a nationwide scale, national ozone transport policy is not well-
served by allowing for less stringent thresholds at Step 2. The EPA 
recognized in the August 2018 memo that there was some similarity in 
the amount of total upwind contribution captured (on a nationwide 
basis) between 1 percent and 1 ppb. However, the EPA notes that while 
this

[[Page 20074]]

may be true in some sense, that is hardly a compelling basis to move to 
a 1 ppb threshold. Indeed, the 1 ppb threshold has the disadvantage of 
losing a certain amount of total upwind contribution for further 
evaluation at Step 3 (e.g., roughly 7 percent of total upwind state 
contribution was lost according to the modeling underlying the August 
2018 memo; \129\ in EPA's updated modeling, the amount lost is roughly 
5 percent). Considering the core statutory objective of ensuring 
elimination of all significant contribution to nonattainment or 
interference of the NAAQS in other states and the broad, regional 
nature of the collective contribution problem with respect to ozone, 
there does not appear to be a compelling policy imperative in moving to 
a 1 ppb threshold.
---------------------------------------------------------------------------

    \129\ See August 2018 memo, at 4.
---------------------------------------------------------------------------

    Consistency with past interstate transport actions such as CSAPR, 
and the CSAPR Update and Revised CSAPR Update rulemakings (which used a 
Step 2 threshold of 1 percent of the NAAQS for two less stringent ozone 
NAAQS) is also important. Continuing to use a 1 percent of NAAQS 
approach ensures that as the NAAQS are revised and made more stringent, 
an appropriate increase in stringency at Step 2 occurs, so as to ensure 
an appropriately larger amount of total upwind-state contribution is 
captured for purposes of fully addressing interstate transport for the 
more stringent NAAQS. EPA made this point when it originally 
promulgated CSAPR to address the 1997 ozone NAAQS. The Agency continues 
to consider this an important consideration for the more stringent 2015 
ozone NAAQS. See 76 FR 48237-38.
    Lastly, the Agency does not find it to be a good use of limited 
resources to attempt to further justify the use of alternative 
thresholds for certain states at Step 2 for purposes of the 2015 ozone 
NAAQS. Therefore, while EPA articulated a potential basis for 
recognizing the usefulness of alternative Step 2 thresholds 
(particularly a 1 ppb threshold) in the August 2018 memorandum, EPA's 
experience and further evaluation since the issuance of that memo has 
revealed substantial programmatic and policy difficulties in attempting 
to implement this approach. Depending on comment and further evaluation 
of this issue, the EPA may determine to rescind the 2018 memorandum in 
the future.
    In light of the considerations above, EPA proposes using a 
contribution threshold of 0.70 ppb as the quantification of 1 percent 
of the 2015 ozone NAAQS for purposes of Step 2.
a. States That Contribute Below the Screening Threshold
    Based on EPA's modeling, the contributions from each of the 
following states to nonattainment or maintenance-only receptors in the 
2023 analytic year are below the 1% of the NAAQS threshold: Arizona, 
Colorado, Connecticut, the District of Columbia, Florida, Georgia, 
Idaho, Iowa, Kansas, Maine, Massachusetts, Montana, Nebraska, New 
Hampshire, New Mexico, North Carolina, North Dakota, Rhode Island, 
South Carolina, South Dakota, Vermont, and Washington. The EPA has 
already approved many of these states' SIP submittals or is in the 
process of taking action to approve them. Because the contributions 
from these states to projected downwind air quality problems are below 
the screening threshold in the current modeling, these states are not 
within the scope of this proposed rule. Additionally, the EPA has made 
proposed or final determinations that two states outside the modeling 
domain for the air quality modeling analyzed in this proposed 
rulemaking--Hawaii \130\ and Alaska \131\--do not significantly 
contribute to nonattainment or interfere with maintenance of the NAAQS 
in any other state.
---------------------------------------------------------------------------

    \130\ The EPA proposed to approve Hawaii's 2015 ozone transport 
SIP on September 28, 2021. See 86 FR 53571.
    \131\ The EPA approved Alaska's 2015 ozone transport SIP on 
December 18, 2019. See 84 FR 69331.
---------------------------------------------------------------------------

a. States That Contribute at or Above the Screening Threshold
    Based on the maximum downwind contributions in Table V.E.1-1, the 
Step 2 analysis identifies that the following 22 states contribute at 
or above the 0.70 ppb threshold to downwind nonattainment receptors in 
2023: Alabama, Arkansas, California, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New 
Jersey, New York, Ohio, Oregon, Pennsylvania, Texas, Utah, Virginia, 
West Virginia, and Wyoming. Based on the maximum downwind contributions 
in Table V.E.1-1, the following 23 states contribute at or above the 
0.70 ppb threshold to downwind maintenance-only receptors in 2023: 
Alabama, Arkansas, California, Delaware, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New 
Jersey, New York, Ohio, Oklahoma, Oregon, Tennessee, Texas, Virginia, 
West Virginia, and Wisconsin. The levels of contribution between each 
of these linked upwind states and downwind nonattainment receptors and 
maintenance-only receptors are provided in the AQM TSD.
    Among the linked states are several western states--California, 
Nevada, Oregon, Utah, and Wyoming. While the EPA has not previously 
included action on linked western states in its prior CSAPR 
rulemakings, the EPA has consistently applied the 4-step framework in 
evaluating good neighbor obligations from these states. On a case-by-
case basis, the EPA has found in some instances with respect to the 
2008 ozone NAAQS that a unique consideration has warranted approval of 
a linked western state's good neighbor SIP submittal without concluding 
that additional emissions reductions are required at Step 3 of the 
framework.\132\ The EPA has also explained in prior actions that its 
air quality modeling is reliable for assessing downwind air quality 
problems and ozone transport contributions from upwind states 
throughout the nationwide modeling domain.\133\
---------------------------------------------------------------------------

    \132\ See interstate transport approval actions under the 2008 
ozone NAAQS for Arizona, California, and Wyoming at 81 FR 36179 
(June 6, 2016), 83 FR 65093 (December 19, 2018), and 84 FR 14270 
(April 10, 2019), respectively.
    \133\ See 81 FR 71991 (October 19, 2016), 82 FR 9155 (February 
3, 2017).
---------------------------------------------------------------------------

    In EPA's current analysis, the EPA finds that for one linked 
state--Oregon--the same considerations that led it to approve another 
state's SIP submission, Arizona's, for the 2008 ozone NAAQS apply to 
Oregon's circumstances for the 2015 ozone NAAQS. As explained in the 
following section, the EPA therefore proposes to affirm its prior 
approval of Oregon's good neighbor SIP submission for the 2015 ozone 
NAAQS. For the remaining western states included in this proposed rule, 
EPA's modeling supports a conclusion that these states are linked above 
the contribution threshold to identified ozone transport receptors in 
other states, and therefore, consistent with the treatment of all other 
states within the modeling domain, the EPA proposes to proceed to 
evaluate these states for a determination of ``significant 
contribution'' at Step 3.
    In conclusion, as described above, states with contributions that 
equal or exceed 1 percent of the NAAQS to either nonattainment or 
maintenance receptors are identified as ``linked'' at Step 2 of the 
good neighbor framework and warrant further analysis for significant 
contribution to nonattainment or interference with

[[Page 20075]]

maintenance under Step 3. The EPA proposes that the following 27 States 
are linked at Step 2 in 2023: Alabama, Arkansas, California, Delaware, 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Oregon, Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming. In addition, the EPA proposes that the 
following 24 States are linked at Step 2 in 2026: Arkansas, California, 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Oregon, Pennsylvania, Texas, Utah, Virginia, West Virginia, Wisconsin, 
and Wyoming. Three states, Alabama, Delaware, and Tennessee, that were 
linked in 2023 are not linked in 2026 because the receptor(s) to which 
each state was linked in 2023 are projected to attain by 2026.

F. Treatment of Certain Receptors in California and Implications for 
Oregon's Good Neighbor Obligations for the 2015 Ozone NAAQS

    The EPA previously approved Oregon's September 25, 2018 transport 
SIP submittal for the 2015 ozone NAAQS on May 17, 2019 (84 FR 22376), 
because in an earlier round of modeling Oregon was not projected to 
contribute above 1 percent of the NAAQS to any downwind receptors. In 
EPA's updated modeling, Oregon is linked above the 1 percent of NAAQS 
threshold to several monitoring sites in California that would 
generally meet EPA's definition of nonattainment or maintenance 
``receptors'' at Step 1.\134\ However, EPA's analysis of the nature of 
the air quality problem at these monitoring sites leads EPA to propose 
a determination that these monitoring sites should not be treated as 
receptors for purposes of determining interstate transport obligations 
of upwind states under CAA section 110(a)(2)(D)(i)(I). EPA reaches this 
conclusion at Step 1 of its four-step framework.
---------------------------------------------------------------------------

    \134\ Monitors are listed in the AQM TSD included in the docket 
for this rulemaking. While EPA is providing information about 
cumulative upwind contribution to the California monitors, the 
Agency does not consider these monitors as ozone transport receptors 
in this proposal.
---------------------------------------------------------------------------

    The EPA previously made a similar assessment of the nature of 
certain other monitoring sites in California in approving Arizona's 
2008 ozone NAAQS transport SIP submittal.\135\ There, the EPA noted 
that a ``factor [. . .] relevant to determining the nature of a 
projected receptor's interstate transport problem is the magnitude of 
ozone attributable to transport from all upwind states collectively 
contributing to the air quality problem.'' \136\ The EPA observed that 
only one upwind state (Arizona) was linked above 1 percent of the 2008 
ozone NAAQS to the two relevant monitoring sites in California, and the 
cumulative ozone contribution from all upwind states to those sites was 
2.5 percent and 4.4 percent of the total ozone, respectively. The EPA 
determined the size of those cumulative upwind contributions was 
``negligible, particularly when compared to the relatively large 
contributions from upwind states in the East or in certain other areas 
of the West.'' \137\ In that action, the EPA concluded the two 
California sites to which Arizona was linked should not be treated as 
receptors for the purposes of determining Good Neighbor obligations for 
the 2008 ozone NAAQS.\138\
---------------------------------------------------------------------------

    \135\ 81 FR 15200 (March 22, 2016) (proposal); 81 FR 31513 (May 
19, 2016) (final rule).
    \136\ 81 FR at 15203.
    \137\ Id.
    \138\ Id.
---------------------------------------------------------------------------

    The EPA proposes to make a similar finding for the monitoring sites 
in California otherwise projected in its current modeling to be 
``receptors'' for the 2015 ozone NAAQS and to which Oregon is linked. 
The highest percent of the total cumulative upwind ozone contribution 
to any of these sites is 2.8 percent.\139\ This is lower than the 
largest transport contribution relative to total ozone at the 
California sites identified in EPA's approval of Arizona's 2008 ozone 
transport SIP (4.4 percent).\140\ Further, as was the case for the 
sites in California analyzed in EPA's Arizona action, the identified 
sites in California each have only one upwind state contributing above 
1 percent of the NAAQS to them (Oregon). These monitoring sites in 
California are overwhelmingly impacted by in-state emissions to a 
degree not comparable with any other identified nonattainment or 
maintenance-only receptors in the country.
---------------------------------------------------------------------------

    \139\ See Air Quality Modeling TSDin the docket for this action.
    \140\ 81 FR at 15203; 81 FR 31513.
---------------------------------------------------------------------------

    The EPA proposes to find that these monitoring sites should not be 
considered receptors for the purpose of assessing 2015 ozone NAAQS 
interstate transport obligations. The EPA is not proposing a different 
contribution threshold at Step 2 for Western states or receptors, nor 
does the EPA reach its conclusion based on any evaluation at Step 3 of 
emissions reduction opportunities in Oregon.
    As a consequence of this proposed finding, the EPA continues to 
find that ozone-precursor emissions from Oregon do not significantly 
contribute to nonattainment or interfere with maintenance of the NAAQS 
in any downwind state, because the total collective upwind state ozone 
contribution to the California monitoring sites is extremely low 
compared to the air quality problems typically addressed under the good 
neighbor provision. Therefore, the EPA is not proposing any change in 
this action to its prior approval of Oregon's SIP. The EPA is not 
proposing any new FIP requirements and is not proposing to require 
reductions from new or existing EGU or non-EGU sources in Oregon in 
this action. If, however, EPA were not to finalize this proposed 
approach, then EPA anticipates that it would apply the same control 
strategies in Oregon as applied in all other linked upwind states, as 
discussed in Sections VI and VII of this proposed rule. EPA requests 
public comment on its approach to characterizing the nature of the 
interstate transport problem at the California monitoring sites at 
issue and the consequent approach to assessing Oregon's good neighbor 
obligations.

VI. Quantifying Upwind-State NOX Emissions Reduction Potential To 
Reduce Interstate Ozone Transport for the 2015 Ozone NAAQS

A. The Multi-Factor Test for Determining Significant Contribution

    This section describes EPA's methodology at Step 3 of the 4-step 
framework for identifying upwind emissions that constitute 
``significant'' contribution for the states subject to this proposed 
rule and focuses on the 26 states with FIP requirements identified in 
the sections above. Following the existing framework as applied in all 
of the prior CSAPR rulemakings, EPA's assessment of linked upwind state 
emissions is based primarily on analysis of several alternative levels 
of NOX emissions control stringency applied uniformly across 
all of the linked states. The analysis includes assessment of non-EGU 
stationary sources in addition to EGU sources in the linked upwind 
states.
    The EPA applies a multi-factor test--the same multi-factor test 
that was used in CSAPR, the CSAPR Update, and the Revised CSAPR Update 
\141\--to evaluate increasing levels of uniform NOX control 
stringency. The multi-factor test, which is central to EPA's Step 3

[[Page 20076]]

quantification of significant contribution, considers cost, available 
emissions reductions, downwind air quality impacts, and other factors 
to determine the appropriate level of uniform NOX control 
stringency that would eliminate significant contribution to downwind 
nonattainment or maintenance receptors. The selection of a uniform 
level of NOX emissions control stringency across all of the 
linked states, reflected as a representative cost per ton of emissions 
reduction (or a weighted average cost per ton in the case of EPA's non-
EGU and EGU analysis for 2026 mitigation measures), also serves to 
apportion the reduction responsibility among collectively contributing 
upwind states. This approach to quantifying upwind state emission-
reduction obligations using uniform cost was reviewed by the Supreme 
Court in EME Homer City Generation, which held that using such an 
approach to apportion emissions reduction responsibilities among upwind 
states that are collectively responsible for downwind air quality 
impacts ``is an efficient and equitable solution to the allocation 
problem the Good Neighbor Provision requires the Agency to address.'' 
572 U.S. at 519.
---------------------------------------------------------------------------

    \141\ See CSAPR, Final Rule, 76 FR 48208 (August 8, 2011).
---------------------------------------------------------------------------

    There are four stages in developing the multi-factor test: (1) 
Identify levels of uniform NOX control stringency; (2) 
evaluate potential NOX emissions reductions associated with 
each identified level of uniform control stringency; (3) assess air 
quality improvements at downwind receptors for each level of uniform 
control stringency; and (4) select a level of control stringency 
considering the identified cost, available NOX emissions 
reductions, and downwind air quality impacts, while also ensuring that 
emissions reductions do not unnecessarily over-control relative to the 
contribution threshold or downwind air quality.
    As mentioned in Section IV.A.2 of this proposed rule, commenters on 
previous ozone transport rules have suggested that the EPA should 
regulate VOCs as an ozone precursor. For this proposed rule, the EPA 
examined the results of the contribution modeling performed for this 
rule to identify the portion of the ozone contribution attributable to 
anthropogenic NOX emissions versus VOC emissions from each 
linked upwind state to each downwind receptor. Of the total upwind-
downwind linkages in 2023, the contributions from NOX 
emissions comprise 80 percent or more of the total anthropogenic 
contribution at the vast majority of linkages (136 out of 140 total). 
Across all receptors, the contribution from NOX emissions 
ranges from 77 percent to 99 percent of the total anthropogenic 
contribution. This review of the portion of the ozone contribution 
attributable to anthropogenic NOX emissions versus VOC 
emissions from each linked upwind state leads the Agency to conclude 
that the vast majority of the downwind air quality areas addressed by 
the proposed rule under are primarily NOX-limited, rather 
than VOC-limited. Therefore, the EPA is proposing to determine that the 
regulation of VOCs as an ozone precursor is not necessary to eliminate 
significant contribution of ozone transport to downwind areas in this 
proposed rule. The remainder of this section focuses on EPA's strategy 
for reducing regional-scale transport of ozone by targeting 
NOX emissions from stationary sources to achieve the most 
effective reductions of ozone transport over the geography of the 
affected downwind areas.
    For both EGUs and non-EGUs, Section VI.B of this proposed rule 
describes the available NOX emissions controls that the EPA 
evaluated for this proposed rule and their representative cost levels 
(in 2016$). Section VI.C of this proposed rule discusses EPA's 
application of that information to assess emissions reduction potential 
of the identified control stringencies. Finally, Section VI.D of this 
proposed rule describes EPA's assessment of associated air quality 
impacts and EPA's subsequent identification of appropriate control 
stringencies considering the key relevant factors (cost, available 
emissions reductions, and downwind air quality impacts).
    This multi-factor approach is consistent with EPA's approach in 
prior transport actions, such as CSAPR. In addition, as was evaluated 
in the CSAPR Update and Revised CSAPR Update, the EPA evaluated 
possible over-control by examining whether an upwind state is linked 
solely to downwind air quality problems that could have been resolved 
at a lesser threshold of control stringency and whether an upwind state 
could reduce its emissions below the 1 percent air quality contribution 
threshold at a lesser threshold of control stringency. This analysis is 
described in Section VI.D of this proposed rule.
    Finally, while the EPA has evaluated potential emissions reductions 
from non-EGU sources in prior rules, this is the first action for which 
the EPA is proposing non-EGU emissions reductions within the context of 
its 4-step interstate transport framework. The EPA applies its multi-
factor test to non-EGUs and independently evaluates non-EGU industries 
in a consistent but parallel track to its Step 3 assessment for EGUs. 
This is consistent with the parallel assessment approach taken for EGUs 
and non-EGUs in the Revised CSAPR Update. Following the conclusions of 
the EGU and non-EGU multi-factor tests, the identified reductions for 
EGUs and non-EGUs are combined and collectively analyzed to assess 
their effects on downwind air quality and whether the rule achieves a 
full remedy to ``significant contribution'' while avoiding over-
control.
    In order to ensure that this rule implements a full remedy for the 
elimination of significant contribution from upwind states, the EPA has 
reviewed available information on all major industrial source sectors 
in the upwind states. This analysis leads the EPA to propose that both 
EGUs and certain large sources in several specific industrial 
categories should be evaluated for emissions control opportunities. As 
discussed in the sections that follow, the EPA proposes that for both 
EGUs and the selected non-EGU source categories, there are impactful 
emissions reduction opportunities available at reasonable cost-
effectiveness thresholds. As in the Revised CSAPR Update, the EPA 
examines EGUs and non-EGUs in this section on consistent but distinct, 
parallel tracks due to differences stemming from the unique 
characteristics of the power sector compared to other industrial source 
categories. Since the NOX SIP Call, EGUs have consistently 
been regulated under ozone transport rules. These units operate in a 
coordinated manner across a highly interconnected electrical grid. 
Their configuration and emissions control strategies are relatively 
homogenous, and their emissions levels and emissions control 
opportunities are generally very well understood due to longstanding 
monitoring and data-reporting requirements. Non-EGU sources, by 
contrast, are relatively heterogeneous, even within a single industrial 
category, and have far greater variation in existing emissions control 
requirements, emissions levels, and technologies to reduce emissions. 
In general, despite these differences, the information available for 
this proposal indicates that both EGUs and certain non-EGU categories 
have available cost-effective NOX emissions reduction 
opportunities at relatively commensurate cost per ton levels, and these 
emissions reductions will make a meaningful improvement in air quality

[[Page 20077]]

at the downwind receptors. Section VI.B.2 of this proposed rule 
describes EPA's process for selecting specific Tier I and Tier II non-
EGU source categories included in this proposed rulemaking.
    The EPA notes that its Step 3 analysis does not assess emissions 
reduction opportunities from mobile sources. The EPA continues to 
believe that title II of the CAA provides the primary authority and 
process for reducing ozone-precursor pollutants from mobile sources. 
EPA's federal mobile source programs have delivered and are projected 
to continue to deliver substantial nationwide reductions in both VOCs 
and NOX emissions; these reductions are factored into the 
Agency's assessment of air quality and contributions at Steps 1 and 2. 
Further, states are generally preempted from regulating new vehicles 
and engines with certain exceptions, and therefore a question exists 
regarding EPA's authority to address such emissions when regulating in 
place of the states under CAA section 110(c). See generally CAA 
sections 209, 177. See also 86 FR 23099. As noted earlier, the EPA 
accounted for mobile source emissions reductions resulting from other 
federally enforceable regulatory programs in the development of 
emissions inventories used to support analysis for this proposed 
rulemaking, and the EPA does not evaluate any mobile source control 
measures in its Step 3 evaluation in this proposal.\142\ For further 
discussion of EPA's existing and ongoing mobile source measures, see 
Section VI.B.4 of this proposed rule.
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    \142\ The EPA recognizes that mechanisms exist under title I of 
the CAA that allow for the regulation of the use and operation of 
mobile sources to reduce ozone-precursor emissions. These include 
motor vehicle inspection and maintenance (I/M) programs, gasoline 
vapor recovery, clean-fuel vehicle programs, transportation control 
programs, and vehicle miles traveled programs. See, e.g., CAA 
sections 182(b)(3), 182(b)(4), 182(c)(3), 182(c)(4), 182(c)(5), 
182(d)(1), 182(e)(3), and 182(e)(4). The EPA views these programs as 
most effective and appropriate in the context of the planning 
requirements applicable to designated nonattainment areas.
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B. Identifying Control Stringency Levels

1. EGU NOX Mitigation Strategies
    In identifying levels of uniform control stringency for EGUs, the 
EPA assessed the same NOX emissions controls that the Agency 
analyzed in the CSAPR Update and the Revised CSAPR Update, all of which 
are considered to be widely available in this sector: (1) Fully 
operating existing SCR, including both optimizing NOX 
removal by existing operational SCRs and turning on and optimizing 
existing idled SCRs; (2) installing state-of-the-art NOX 
combustion controls; (3) fully operating existing SNCRs, including both 
optimizing NOX removal by existing operational SNCRs and 
turning on and optimizing existing idled SNCRs; (4) installing new 
SNCRs; (5) installing new SCRs; and (6) generation shifting (i.e., 
emission reductions anticipated to occur from generation shifting from 
higher to lower emitting units at each of these stringency levels). For 
the reasons explained in the EGU NOX Mitigation Strategies 
Proposed Rule TSD included in the docket for this proposed rule, the 
EPA determined that for the regional, multi-state scale of this 
rulemaking, only EGU NOX emissions controls 1, 3, and 6 are 
possible for the 2023 ozone season (fully operating existing SCRs and 
SNCRs, and associated generation shifting). The EPA finds that it is 
not possible to install state-of-the-art NOX combustion 
controls by the 2023 ozone season on a regional scale for Group 3 
states not covered under the Revised CSAPR Rule. The EPA also 
determined that state-of-the-art NOX combustion controls at 
EGUs are available by the beginning of the 2024 ozone season. All cost 
values discussed below for EGUs are in 2016 dollars.
a. Optimizing Existing SCRs
    Optimizing (i.e., turning on idled or improving operation of 
partially operating) existing SCRs can substantially reduce EGU 
NOX emissions quickly, using investments that have already 
been made in pollution control technologies. With the promulgation of 
the CSAPR Update and the Revised CSAPR Update, most operators in the 
covered states improved their SCR performance and have continued to 
maintain that level of improved operation. However, this optimized SCR 
performance was not universal and not always sustained. Between 2017 
and 2020, as the CSAPR Update ozone-season NOX allowance 
price declined, NOX emissions rates at some SCR-controlled 
EGUs increased. For example, power sector data from 2019 revealed that, 
in some cases, operating units had SCR controls that had been idled or 
were operating partially, and therefore suggested that there remained 
emissions reduction potential through optimization.\143\ The EPA 
determined that optimizing all of these remaining SCRs in the 12 linked 
states for the Revised CSAPR Update was a readily available approach 
for EGUs to reduce NOX emissions. This emissions reduction 
measure is currently available at EGUs across the broader geography 
affected in this proposed rulemaking (including in states not 
previously affected by the Revised CSAPR Update). The EPA thus proposes 
that SCR optimization, of both idled and partially operating controls, 
is a viable mitigation strategy for the 2023 ozone season.
---------------------------------------------------------------------------

    \143\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired 
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    The EPA estimates a representative marginal cost of optimizing SCR 
controls to be approximately $1,600 per ton, consistent with its 
estimation in the Revised CSAPR Update for this technology. EPA's EGU 
NOX Mitigation Strategies Proposed Rule TSD for this rule 
describes a range of cost estimates for this technology noting that the 
costs are frequently lower than--and for the majority of EGUs, 
significantly lower than--this representative marginal cost. While the 
costs of optimizing existing, operational SCRs include only variable 
costs, the cost of optimizing SCR units that are currently idled 
considers both variable and fixed costs of returning the control into 
service. Variable and fixed costs include labor, maintenance and 
repair, parasitic load, and ammonia or urea for use as a NOX 
reduction reagent in SCR systems. Depending on a unit's control 
operating status, the representative cost at the 90th percentile unit 
(among the relevant fleet of coal units with SCR covered in this 
rulemaking) ranges between $900 and $1,700 per ton. The EPA performed 
an in-depth cost assessment for all coal-fired units with SCRs and 
found that for the subset of SCRs that are already partially operating, 
the cost of optimizing is often much lower than $1,600 per ton and is 
often under $900 per ton. The EPA anticipates the vast majority of 
realized cost for compliance with this strategy to be better reflected 
by the $900 per ton end of that range (reflecting the 90th percentile 
of EGUs optimizing SCRs that are already partially operating) because 
this circumstance is considerably more common than EGUs that have 
ceased operating their SCR. EPA's analysis of this emissions control is 
informed by the latest engineering modeling equations used in EPA's IPM 
platform. These cost and performance equations were recently updated in 
the summer of 2021. The description and development of the equations 
are documented in EGU NOX Mitigation Strategies Proposed 
Rule TSD and accompanying documents.\144\ They are also

[[Page 20078]]

implemented in an interactive spreadsheet tool called the Retrofit Cost 
Analyzer and applied to all units in the fleet. These materials are 
available in the docket for this proposal.
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    \144\ The CSAPR Update estimated $1,400 per ton as a 
representative cost of turning on idled SCR controls. EPA used the 
same costing methodology while updating for input cost increases 
(e.g., urea reagent) to arrive at $1,600 per ton in the final 
Revised CSAPR Update (while also updating from 2011 dollars to 2016 
dollars).
---------------------------------------------------------------------------

    The EPA is using the same methodology to identify SCR performance 
as it did in the Revised CSAPR Update. To estimate EGU NOX 
reduction potential from optimizing, the EPA considers the difference 
between the non-optimized NOX emissions rates and an 
achievable operating and optimized SCR NOX emissions rate. 
To determine this rate, EPA evaluated nationwide coal-fired EGU 
NOX ozone season emissions data from 2009 through 2019 and 
calculated an average NOX ozone season emissions rate across 
the fleet of coal-fired EGUs with SCR for each of these eleven years. 
The EPA found it prudent to not consider the lowest or second-lowest 
ozone season NOX emissions rates, which may reflect SCR 
systems that have all new components (e.g., new layers of catalyst). 
Data from these systems are potentially not representative of ongoing 
achievable NOX emissions rates considering broken-in 
components and routine maintenance schedules. To identify the potential 
reductions from SCR optimization in this proposed rule, the EPA 
followed the same methodology as the Revised CSAPR Update. Considering 
the emissions data over the full time period from 2009-2019 data 
results in a third-best rate of 0.079 pounds NOX per million 
British thermal units (lb/mmBtu).\145\ Therefore, consistent with the 
Revised CSAPR Update, where EPA identified 0.08 lb/mmBtu as a 
reasonable level of performance for units with optimized SCR, the EPA 
proposes a rate of 0.08 lb/mmBtu as the optimized rate for this rule. 
The EPA notes that half of the SCR-controlled EGUs achieved a 
NOX emissions rate of 0.064 lbs/mmBtu or less over their 
third-best entire ozone season. Moreover, for the SCR-controlled coal 
units that the EPA identified as having a 2021 emissions rate greater 
than 0.08 lb/mmBtu, the EPA verified that in prior years, the majority 
(more than 90 percent) of these same units had demonstrated and 
achieved a NOX emissions rate of 0.08 lb/mmBtu or less on a 
seasonal or monthly basis. This further supports EPA's determination 
that 0.08 lb/mmBtu reflects a reasonable emissions rate for 
representing SCR optimization at coal steam units in identifying 
uniform control stringency. This emissions rate assumption of 0.08 lb/
mmBtu reflects what those units would achieve on average when 
optimized, recognizing that individual units may achieve lower or 
higher rates based on unit-specific configuration and dispatch 
patterns. Units historically performing at, or better, than this rate 
of 0.08 lb/mmBtu are assumed to continue to operate at that prior 
performance level.
---------------------------------------------------------------------------

    \145\ The EPA notes that updating the inventory of units to 
reflect recent retirements and most recent year data (e.g., 2009-
2021) would provide a lower value of 0.071 lb/mmBtu. This value is 
lower than the 0.08 pounds per million British thermal units (lb/
mmBtu) assessed in the Revised CSAPR Update as it reflects 2020 data 
and also excludes the SCR performance of since retired coal units 
with SCRs. However, 2020 was an outlier year (related to pandemic 
impacts on the electric grid). Additionally, a unit's retirement 
does not obviate the usefulness of its data for assessing technology 
performance. Consequently, EPA is proposing the same value of 0.08 
lb/mmBtu identified at the time of the final Revised CSAPR Update 
Rule.
---------------------------------------------------------------------------

    Given the magnitude and duration of the air quality problems 
addressed by this rulemaking, the EPA also applied the same methodology 
to identify a reasonable level of performance for optimizing existing 
SCRs at oil- and gas-fired steam units and simple cycle units (for 
which EPA determined that a 0.03 lb/mmBtu emissions rate reflected SCR 
optimization) as well as at combined-cycle units (for which the EPA 
determined that a 0.012 lb/mmBtu emissions rate reflected SCR 
optimization).
    The EPA evaluated the feasibility of optimizing idled SCRs for the 
2023 ozone season. Based on industry past practice, the EPA determined 
that idled controls can be restored to operation quickly (i.e., in less 
than 2 months). This timeframe is informed by many electric utilities' 
previous long-standing practice of utilizing SCRs to reduce EGU 
NOX emissions during the ozone season while putting the 
systems into protective lay-up during the non-ozone season months. For 
example, this was the long-standing practice of many EGUs that used SCR 
systems for compliance with the NOX Budget Trading Program. 
It was quite typical for SCRs to be turned off following the September 
30 end of the ozone season control period. These controls would then be 
put into protective lay-up for several months of non-use before being 
returned to operation by May 1 of the following ozone season.\146\ 
Therefore, the EPA believes that optimization of existing SCRs is 
possible for the portion of the 2023 ozone season covered under this 
proposed rule.
---------------------------------------------------------------------------

    \146\ In the 22-state CSAPR Update region, 2005 EGU 
NOX emissions data suggest that 125 EGUs operated SCR 
systems in the summer ozone season while idling these controls for 
the remaining 7 non-ozone season months of the year. Units with SCR 
were identified as those with 2005 ozone season average 
NOX rates that were less than 0.12 lbs/mmBtu and 2005 
average non-ozone season NOX emissions rates that 
exceeded 0.12 lbs/mmBtu and where the average non-ozone season 
NOX rate was more than double the ozone season rate.
---------------------------------------------------------------------------

    The vast majority of SCR-controlled units (nationwide and in the 25 
linked states for which EPA is issuing a FIP for EGUs) are already 
partially operating these controls during the ozone season based on 
reported 2021 emissions rates. Existing SCRs operating at partial 
capacity still provide functioning, maintained systems that may only 
require an increased chemical reagent feed rate (i.e., ammonia or urea) 
up to their design potential and catalyst maintenance for mitigating 
NOX emissions; such units may require increased frequency or 
quantity of deliveries, which can be accomplished within a few weeks. 
In many cases, EGUs with SCR have historically achieved more efficient 
NOX removal rates than their current performance and can 
therefore simply revert to earlier operation and maintenance plans that 
achieved demonstrably better SCR performance.
    In the 12 states subject to this control stringency in the Revised 
CSAPR Update, the EPA observed significant immediate-term improvements 
in SCR performance in the first ozone season following finalization of 
that rule, as evidenced in particular by the sharp drop in emissions 
rate at Miami Fort unit 7 (see EGU NOX Mitigation Strategies 
Proposed Rule TSD). Such empirical data further illustrates the 
viability of this mitigation strategy for the 2023 control period in 
response to this rule.
b. Installing State-of-the-Art NOX Combustion Controls
    The EPA estimates that the representative cost of installing state-
of-the-art combustion controls is comparable to, if not notably less 
than, the estimated cost of optimizing existing SCR (represented by 
$1,600 per ton). State-of-the-art combustion controls such as low-
NOX burners (LNB) and over-fire air (OFA) can be installed 
or updated quickly and can substantially reduce EGU NOX 
emissions. Nationwide, approximately 99 percent of coal-fired EGU 
capacity greater than 25 MW is equipped with some form of combustion 
control; however, the control configuration or corresponding emissions 
rates at a small portion of those units (including units in those 
states covered in this action) indicate they do not currently have 
state-of-the-

[[Page 20079]]

art combustion control technology. As described in the Revised CSAPR 
Update, the Agency updated its NOX emissions rates for 
upgrading existing combustion controls to state-of-the-art combustion 
control. The EPA is maintaining its determination that NOX 
emissions rates of 0.146 to 0.199 lbs/mmBtu can be achieved on average 
depending on the unit's boiler configuration,\147\ and, once installed, 
reduce NOX emissions at all times of EGU operation.
---------------------------------------------------------------------------

    \147\ Details of EPA's assessment of state-of-the-art 
NOX combustion controls are provided in the EGU 
NOX Mitigation Strategies Proposed Rule TSD.
---------------------------------------------------------------------------

    These assumptions are consistent with the Revised CSAPR Update and 
they are further discussed in the EGU NOX Mitigation 
Strategies Proposed Rule TSD. In particular, the EPA proposes to apply 
the 0.199 lb/mmBtu emissions rate assumption for all unit types, 
consistent with its determination in the Revised CSAPR Update. The 
average emissions rate assumption derived from EPA's analysis would be 
0.199 lb/mmBtu for combustion controls on dry bottom wall fired units 
and 0.146 lb/mmBtu for tangentially fired units. However, stakeholders 
have provided detailed analysis of how other unit considerations, such 
as coal rank, can result in large deviations from what has been 
historically demonstrated with this combustion control technology. 
Based on this and EPA's review of historical performance data for 
tangentially-fired units by coal rank with state-of-the-art combustion 
controls, the EPA determined in the final Revised CSAPR Update that it 
was appropriate to use the 0.199 lb/mmBtu rate for both tangentially 
and wall-fired units when estimating reduction potential for units with 
combustion control upgrade potential.
    The EPA proposes to continue that approach in this action. Many of 
the likely impacted units burn bituminous coal, and the 0.146 lb/mmBtu 
nationwide average for tangentially-fired (inclusive of subbituminous 
units) appears to be below the demonstrated emissions rate of state-of-
the-art combustion controls for bituminous coal units of this boiler 
type. Therefore, EPA's assumption of 0.199 lb/mmBtu for combustion 
controls is robust to current and future coal choice at a unit.
    In promulgating CSAPR, the EPA examined the feasibility of 
installing combustion controls, and found that industry had 
demonstrated ability to install state-of-the-art LNB controls on a 
large unit (800 MW) in under six months when including the pre-
installation phases (design, order placement, fabrication, and 
delivery).\148\ In prior rules, the EPA has documented its own 
assessment of combustion control timing installation as well as 
evaluated comments it received regarding installation of combustion 
controls from the Institute of Clean Air Companies.\149\ Those comments 
provided information on the equipment and typical installation time 
frame for new combustion controls, accounting for all steps. Commenters 
noted that it generally takes between 6-8 months on a typical boiler--
covering the time through bid evaluation through start-up of the 
technology. The deployment schedule is repeated here as:
---------------------------------------------------------------------------

    \148\ The EPA finds that, generally, the installation phase of 
state-of-the-art combustion control upgrades--on a single-unit 
basis--can be as little as 4 weeks to install with a scheduled 
outage (not including the pre-installation phases such as 
permitting, design, order, fabrication, and delivery) and as little 
as 6 months considering all implementation phases.
    \149\ EPA-HQ-OAR-2015-0500-0093.

 4-8 weeks--bid evaluation and negotiation
 4-6 weeks--engineering and completion of engineering drawings
 2 weeks--drawing review and approval from user
 10-12 weeks--fabrication of equipment and shipping to end user 
site
 2-3 weeks--installation at end user site
 1 week--commissioning and start-up of technology

Given the above timeframe of approximately 6 to 8 months to complete 
combustion control installation in the region, the EPA is proposing to 
determine that installation of state-of-the-art combustion controls is 
a readily available approach for EGUs to reduce NOX 
emissions by the start of the 2024 ozone season. More details on these 
analyses can be found in the EGU NOX Mitigation Strategies 
Proposed Rule TSD.
    The cost of installing state-of-the-art combustion controls per ton 
of NOX reduced is dependent on the combustion control type 
and unit type. The EPA estimates the cost per ton of state-of-the-art 
combustion controls to be $400 per ton to $1,200 per ton of 
NOX removed using a representative capacity factor of 85 
percent. This cost fits well within EPA's representative cost threshold 
observed for SCR optimization and combustion controls (of $1,600 per 
ton) which would accommodate combustion control upgrade even under 
scenarios where a lower capacity factor is assumed. See the EGU 
NOX Mitigation Strategies Proposed Rule TSD for additional 
details.
c. Optimizing Already Operating SNCRs or Turning on Idled Existing 
SNCRs
    Optimizing already operating SNCRs or turning on idled existing 
SNCRs can also reduce EGU NOX emissions quickly, using 
investments in pollution control technologies that have already been 
made. Compared to no post-combustion controls on a unit, SNCRs can 
achieve a 25 percent reduction on average in EGU NOX 
emissions (with sufficient reagent). They are less capital intensive 
but less efficient at NOX removal than SCRs. These controls 
are in use to some degree across the U.S. power sector. In the 25 
linked states identified in this proposed rule with identified EGU 
reductions in their proposed FIP, approximately 11 percent of coal-
fired EGU capacity is equipped with SNCR.\150\ Recent power sector data 
suggest that, in some cases, SNCR controls have been operating less in 
2021 relative to performance in prior years.
---------------------------------------------------------------------------

    \150\ https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
---------------------------------------------------------------------------

    The EPA determined that optimizing already operating SNCRs or 
turning on idled SNCRs is an available approach for EGUs to reduce 
NOX emissions, has similar implementation timing to 
restarting idled SCR controls (less than 2 months for a given unit), 
and therefore could be implemented in time for the 2023 ozone season. 
The EPA is proposing implementation of this emissions control 
technology beginning in the 2023 ozone season.
    Using an updated data assessment using the Retrofit Cost Analyzer 
described in the EGU NOX Mitigation Strategies Proposed TSD, 
the EPA estimates a representative cost of optimizing SNCR ranging from 
approximately $1,800 per ton (for partially operating SNCRs) to $3,900 
per ton (for idled SNCRs). For existing SNCRs that have been idled, 
unit operators may need to restart payment of some fixed and variable 
operating costs including labor, maintenance and repair, parasitic 
load, and ammonia or urea. The EPA determined that the majority of 
units with existing SNCR optimization potential were already partially 
operating their controls. Therefore, the EPA proposes a representative 
cost of $1,800 per ton for SNCR optimization as this value best 
reflects the circumstances of the majority of the affected EGUs with 
SNCR.

[[Page 20080]]

d. Installing New SNCRs
    Like existing SNCRs, new SNCR retrofit is also available to power 
plants and can achieve a 25% NOX reduction on average. The 
EPA evaluated potential emissions reductions and associated costs from 
retrofitting EGUs with new SNCR post-combustion controls at steam units 
lacking such controls. New SNCR technology provides owners with a 
relatively less capital-intensive option for reducing NOX 
emissions compared to new SCR technology, albeit at the expense of 
higher operating costs on a per-ton basis and less total emissions 
reduction potential. SNCR is more widely observed on relatively smaller 
coal units given its low capital/variable cost ratio. The average 
capacity of a coal unit with SNCR is half the size of the average 
capacity of coal unit with SCR.\151\ Given these observations, the EPA 
identifies this technology as an emissions reduction measure for coal 
units less than 100 MW lacking post-combustion NOX control 
technology. As described in the EGU NOX Mitigation 
Strategies Proposed Rule TSD, the EPA estimated that $6,700 per ton 
reflects a representative SNCR retrofit cost level for a majority of 
these units.
---------------------------------------------------------------------------

    \151\ See EGU NOX Mitigation Strategies Proposed Rule 
TSD for additional discussion.
---------------------------------------------------------------------------

    SNCR installations generally have shorter project installation 
timeframes relative to other post-combustion controls. The time for 
engineering review, contract award, fabrication, delivery, and hookup 
is as little as 16 months including pre-contract award steps for an 
individual power plant installing controls on more than one boiler. 
This timeframe would mean the control would be available for the start 
of the 2024 or 2025 ozone season (i.e., calculating 16 months from when 
this proposal is finalized). However, SNCR retrofits have less 
pollution reduction potential than alternative post-combustion controls 
such as SCRs. The EPA is not identifying SNCR technology as a strategy 
for larger steam units due to this lower removal efficiency and the 
empirical evidence of existing sources preferring the more efficient 
SCRs. Even for those smaller units less than 100 MWs identified as 
potential candidates for this technology, the EPA does not want to 
preclude those units from pursuing more advanced pollution controls. 
Therefore, the EPA also considers the point in time when all types of 
post-combustion control installation could be achieved--i.e., by the 
2026 ozone season. SNCR installation share similar implementation steps 
with and also need to account for the same regional factors as SCR 
installations.\152\ Therefore, while the EPA is determining that at 
least 16 months would be needed to complete all necessary steps of SNCR 
development and installation at the EGUs not currently equipped with 
SNCRs in the 25 states linked to downwind receptors in this proposed 
rule, the EPA notes that the Agency evaluated SNCR as a post-combustion 
control technology collectively with SCR and estimated installation 
timing considerations of 36 months. EPA believes its proposed 
collective timing considerations for post-combustion control retrofit 
(SNCR and SCR) are practicable given that the preferable capital-
intensive investment retrofit decision would be highly unit-specific 
and subject to a unit's compliance strategy choices with respect to 
multiple regulatory requirements.
---------------------------------------------------------------------------

    \152\ A month-by-month evaluation of SNCR installation is 
discussed in EPA's NOX Mitigation Strategies Proposed 
Rule TSD and in EPA's ``Engineering and Economic Factors Affecting 
the Installation of Control Technologies for Multipollutant 
Strategies''. The analysis in this exhibit estimates the 
installation period from contract award as within a 10-13-month 
timeframe. The exhibit also indicates a 16-month timeframe from 
start to finish, inclusive of pre-contract award steps of the 
engineering assessment of technologies and bid request development. 
The timeframe cited for installation of SNCR at an individual source 
in this action is consistent with this more complete timeframe 
estimated by the analysis in the exhibit.
---------------------------------------------------------------------------

    Nonetheless, the EPA is requesting comment on whether post-
combustion control timing assumptions (SCR and SNCR) should be 
decoupled, which would result in the EPA using the 16-month time frame 
specific to SNCR installation to estimate the first year in which these 
reductions are available. The EPA is only identifying this technology 
for units less than 100 MW (a size at which units rarely implement SCR 
retrofit technology). In effect, decoupling these timing assumptions 
would move the reductions associated with this control stringency from 
beginning in the 2026 ozone season to beginning in the 2024 or 2025 
ozone season (depending on when this proposal is finalized). This would 
impact approximately 1,000 tons of identified reduction potential 
related to SNCR retrofit.
e. Installing New SCRs
    Selective Catalytic Reduction (SCR) controls already exist on 
approximately 60% of the coal fleet in the linked states that would be 
subject to a FIP in this proposed rulemaking. Nearly every pulverized 
coal unit larger than 100 MW built in the last 30 years has installed 
this control, which is generally required for Best Available Control 
Technology (BACT) purposes. Other than circulating fluidized bed coal 
units which can achieve a comparably low emissions rate without this 
technology, the EPA identifies this emissions reduction measure for 
coal steam units greater than or equal to 100 MW. SCR is widely 
available for existing coal units of this size and can provide 
significant emissions reduction potential, with removal efficiencies of 
up to 90 percent. The EPA limited its consideration of SCR technology 
to steam units greater than or equal to 100 MW. The costs for 
retrofitting a plant smaller than 100 MW with SCR increase rapidly due 
to a lack of economy of scale.\153\
---------------------------------------------------------------------------

    \153\ IPM Model-Updates to Cost and Performance for APC 
Technologies. SCR Cost Development Methodology for Coal-fired 
Boilers. February 2022.
---------------------------------------------------------------------------

    The amount of time needed to retrofit an EGU with new SCR extends 
beyond the 2023 ozone season. The EPA proposes that a strategy of 
retrofitting new SCR on a fleetwide, regional scale is available by, 
but no earlier than, the 2026 ozone season. Similar to the SNCR 
retrofits discussed above, the EPA evaluated potential emissions 
reductions and associated costs from this control technology, as well 
as the impacts and need for this emissions control strategy, at the 
earliest point in time when their installation could be achieved. In 
the past, the EPA has found the amount of time to retrofit a single EGU 
with new SCR, depending on the regulatory program under which such 
control may be required, may vary between approximately 2 and 4 years 
depending on site-specific engineering considerations and on the number 
of installations being considered. This includes steps for engineering 
review, construction permit, operating permit, and control technology 
installation (including fabrication, pre hookup, control hookup, and 
testing). EPA's assessment of installation procedures suggests as 
little as 21 months may be needed for a single SCR at an individual 
plant and 36 months at a single plant with multiple boilers. EPA's 
assessment of units with SCR retrofit potential indicate the majority 
fall into this first classification, i.e., a single SCR at a power 
plant. Given that some of the assumed SCR retrofit potential occurs at 
plants with multiple units identified with retrofit potential, and 
given the total volume of SCR retrofit capacity being implemented 
across the region, The EPA is proposing 36 months as an appropriate 
time frame to accommodate both instances as well as scheduling 
necessities attributable to the regional-scale nature of the program.

[[Page 20081]]

    Further, the EPA notes that it has previously determined in the 
context of ozone transport that regional scale implementation of SCRs 
at numerous EGUs is achievable in 36 months. See 63 FR 57356, 57447-50 
(October. 27, 1998). The EPA has at times also found up to 39-48 months 
to be an appropriate installation timeframe for regionwide actions when 
the EPA is evaluating multiple installations at multiple 
locations.\154\ However, as discussed in greater detail in Section 
VII.A in this proposed rule, the EPA now recognizes that the Wisconsin 
decision invalidated the standard under which the EPA had been 
evaluating appropriate compliance timeframes for purposes of assessing 
interstate transport under the good neighbor provision when the Agency 
had concluded a 39-48 month timeframe to install SCR was appropriate.
---------------------------------------------------------------------------

    \154\ See, e.g., CSAPR Close-Out, 83 FR 65878, 65895 (December 
21, 2018). See also Final Report: Engineering and Economic Factors 
Affecting the Installation of Control Technologies for 
Multipollutant Strategies, EPA-600/R-02/073 (Oct. 2002), available 
at https://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf.
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    The Agency examined the cost for retrofitting a coal unit with new 
SCR technology, which typically attains controlled NOX rates 
of 0.05 lbs/mmBtu or less. These updates are further discussed in the 
EGU NOX Mitigation Strategies Proposed Rule TSD.\155\ Based 
on the characteristics of coal units of 100 MW or greater capacity that 
do not have post-combustion NOX control technology, the EPA 
estimated a weighted-average representative SCR cost of $11,000 per 
ton.\156\
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    \155\ As noted in that TSD, approximately half of the recent SCR 
retrofits (i.e., installed in the last 10 years) have demonstrated 
an emission rate across the ozone season below 0.05 lb/mmBtu, even 
absent a requirement or strong incentive to operate at that level in 
many cases.
    \156\ This cost estimate is representative of coal units lacking 
any post-combustion control. A subset of units within the universe 
of coal sources with SCR retrofit potential, but that have an 
existing SNCR technology in place would have a weighted average cost 
that falls above this level, but still cost effective. See the EGU 
NOX Mitigation Strategies Proposed Rule TSD for more 
discussion.
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    The 0.05 lb/mmBtu emission rate performance assumption for new SCR 
retrofits is supported by historical data and third party independent 
review by pollution control engineering and consulting firms. The EPA 
first examined unit-level emission rate data for coal-fired units that 
had a relatively recent SCR installation (within the last 10 years). 
These SCR retrofits reflect the most recent vintage of the pollution 
control technology applied to the power sector and are representative 
of new SCR retrofit capability. Although regulatory requirements or 
economic incentives were not necessarily in place during this time 
period for these SCRs to operate at their full potential, the EPA found 
that half of these units had still demonstrated a seasonal emission 
rate of 0.05 lb/mmBtu or lower and 78 percent had demonstrated this 
rate on a monthly basis. The best performing 10 percent of these SCRs 
were demonstrating seasonal emission rates of 0.036 lb/mmBtu during 
this time.
    While the EPA identified the 0.05 lb/mmBtu performance assumption 
consistent with historical data, these performance levels are also 
informed and consistent with the Agency's IPM modeling assumptions used 
for more than a decade. These modeling assumptions are based on input 
from leading engineering and pollution control consulting entities. 
Most recently, these data assumptions were affirmed and updated in the 
summer of 2021 and included in the docket for this rulemaking. The EPA 
relies on a global firm providing engineering, construction management, 
and consulting services for power and energy with expertise in grid 
modernization, renewable energy, energy storage, nuclear power, and 
fossil fuels. Their familiarity with state-of-the art pollution 
controls at power plants derives from experience providing 
comprehensive project services--from consulting, design, and 
implementation to construction management, commissioning, and 
operations/maintenance. This review and update supported the 0.05 lb/
mmBtu performance assumption as a representative emission rate for new 
SCR across coal types.
    The EPA performed an assessment for oil/gas steam units in which it 
evaluated the nationwide performance of those units with SCR 
technology. For these units, the EPA tabulated EGU NOX ozone 
season emissions data from 2009 through 2021 and calculated an average 
NOX ozone season emissions rate across the fleet of oil- and 
gas-fired EGUs with SCR for each of these years. The EPA identified the 
third lowest year which yielded an SCR performance rate of 0.03 lb/
mmBtu as representative of performance for this retrofit technology 
applied to this type of EGU. Next, the EPA evaluated the emissions and 
operational characteristics for the existing oil/gas steam fleet 
lacking SCR technology. EPA's analysis indicated that the majority of 
reduction potential (approximately 76 percent) from these units 
occurred at units greater than or equal to 100 MW and that were 
emitting more than 150 tons per ozone season (i.e., approximately 1 ton 
per day). Moreover, the cost of reductions for units falling below 
these criteria increased significantly. Therefore, the EPA identified 
the portion of the oil/gas steam fleet meeting this criteria as 
representative of the SCR retrofit reduction potential.\157\ For this 
segment of the oil/gas steam units lacking post-combustion 
NOX control technology, the EPA estimated a weighted-average 
representative SCR cost of $7,700 per ton.
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    \157\ The EPA used a 3 year average of 2019-2021 reported ozone 
season emissions to derive a tons per ozone season value 
representative for each covered oil/gas steam unit.
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f. Generation Shifting
    Finally, EPA evaluates emissions reduction potential from 
generation shifting across the representative dollar per ton levels 
estimated for the emissions controls considered above. As the cost of 
emitting NOX increases, it becomes increasingly cost-
effective for units with lower NOX rates to increase 
generation, while units with higher NOX rates reduce 
generation. Because the cost of generation is unit-specific, this 
generation shifting occurs incrementally on a continuum. Consequently, 
there is more generation shifting at higher cost NOX-control 
levels.
    It is reasonable for the EPA to quantify and include the emissions 
reduction potential from generation shifting at cost levels that are 
representative of the emissions control technologies evaluated in the 
multi-factor analysis, because all EGUs that would be regulated by this 
proposed rule participate in highly coordinated, interconnected systems 
where generation shifting will inevitably occur in response to 
pollution control requirements. If the EPA did not account for such 
emissions reduction potential in its analysis at Step 3, seeking 
emissions reductions from pollution control measures at higher-
NOX-emitting EGUs would still incentivize generation 
shifting toward lower-NOX-emitting EGUs when sources comply 
under the remedy mechanism established in Step 4, and the corresponding 
reductions in emissions achieved through such generation shifting would 
potentially substitute for some of the emissions reductions intended 
through control operation and installation, potentially lessening the 
implementation of those mitigation strategies. Generation shifting 
treatment and results are discussed in greater detail in the EGU 
NOX Mitigation Strategies Proposed TSD and the Ozone 
Transport Policy Analysis Proposed Rule TSD.

[[Page 20082]]

    The EPA notes that its treatment of generation shifting here is 
consistent with the prior CSAPR rulemakings and is grounded on the same 
statutory authority. See, e.g., 76 FR 48208, 48280 (August 8, 2011). As 
the EPA explained in the CSAPR Update: \158\
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    \158\ The EPA discussed its legal authority for and the 
technical viability of generation shifting as a method of emissions 
reduction under the good neighbor provision in the CSAPR Update. See 
especially 81 FR 74504, 74545-47; see also CSAPR Update Response to 
Comment Document at 546-550 (legal authority); id. 528-533 
(technical feasibility). See Final Revised CSAPR Update, 86 FR 
23096-97.

    The good neighbor provision requires state and federal plans 
implementing its requirements to ``prohibit[ ] . . . any source or 
other type of emissions activity within the State from emitting any 
air pollutant in amounts which will'' significantly contribute to 
nonattainment or interfere with maintenance of the NAAQS in any 
other state. CAA section 110(a)(2)(D)(i)(I) (emphasis added). . . . 
[T]he statute does not limit the EPA's authority under the good 
neighbor provision to basing regulation only to control strategies 
for individual sources. The statute authorizes the state or EPA in 
promulgating a plan to prohibit emissions from ``any source or other 
type of emissions activity within the State'' that contributes (as 
determined by EPA) to the interstate transport problem with respect 
to a particular NAAQS. This broad statutory language shows that 
Congress was directing the states and the EPA to address a wide 
range of entities and activities that may be responsible for 
downwind emissions. However, this provision is silent as to the type 
of emissions reduction measures that the states and the EPA may 
consider in establishing emissions reduction requirements, and it 
does not limit those measures to individual source controls. . . . 
The EPA reasonably interprets this provision to authorize 
consideration of a wide range of measures to reduce emissions from 
sources, which is consistent with the broad scope of this provision, 
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as noted immediately above.

81 FR 74545.\159\ The EPA continued to apply this same understanding in 
the Revised CSAPR Update. See 86 FR 23054, 23095-97 (April 30, 2021); 
see also 85 FR 68964, 68992-93 (October 30, 2020).
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    \159\ The EPA also noted in the CSAPR Update, ``Interpreting the 
Good Neighbor Provision to be sufficiently broad to authorize 
reliance on generation shifting is also consistent with the 
legislative history for the 1970 CAA Amendments. The Senate Report 
stated that to achieve the NAAQS, `[g]reater use of natural gas for 
electric power generation may be required,' S. Rep. No. 91-1196 at 
2.'' 81 FR 74545 n.141.
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    The EPA requests comment on the suite of mitigation technologies 
for EGUs described earlier and assessed in the determination of 
significant contribution. The EPA requests comment on the assumed 
performance or emissions rate of the technology, the representative 
cost, and the timing for installation.\160\ Additionally, the EPA 
requests comment on whether other EGU ozone-season NOX 
Mitigation technologies should be required to eliminate significant 
contribution. For instance, the EGU NOX Mitigation 
Strategies Proposed Rule TSD discusses certain mitigation technologies 
that have been applied to ``peaking'' units (small, low capacity factor 
gas combustion turbines often only operating during periods of peak 
demand). To the extent that any of these sources meet the applicability 
requirements and are covered in the Group 3 trading program under this 
proposed rulemaking, they would have an incentive to reduce emissions 
consistent with the ozone season NOX allowance price. The 
EPA has not identified determinative evidence that there are additional 
meaningful, cost-effective upwind reductions from these emission 
controls that are not already being addressed by state rules. EPA's 
analysis discussed in the EGU NOX Mitigation Strategies 
Proposed Rule TSD highlights that there are 32 units emitting more than 
10 tons per year on average for the 2019-2021 ozone seasons and lacking 
combustion controls or more advanced controls (totaling approximately 
1,000 tons of ozone season NOX emissions in 2021). Some of 
the units in the limited inventory are subject to state requirements 
delivering additional reductions by 2023. Moreover, the EPA analysis 
suggested $25,000-$30,000 per ton estimates for dry low NOX 
burners or ultra-low NOX burners at these units, and over 
$100,000 per ton for SCR retrofit at some combustion turbines. 
Therefore, the EPA is not proposing any additional reductions from new 
controls for inclusion in its combustion control or retrofit technology 
breakpoints. Although the EPA is not proposing a mitigation technology 
for this type of unit, it requests comment on the potential emissions 
reductions and cost from such sources in covered states that do not 
currently have mitigation requirements for such sources.
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    \160\ The feasibility of the timetable for emissions reductions 
from both EGUs and non-EGUs is further addressed in Section VII.A of 
this proposed rule.
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2. Non-EGU NOX Mitigation Strategies
a. Determining Non-EGU NOX Reduction Potential
    The number of different industries and emissions unit categories 
and types, as well as the total number of emissions units that comprise 
the universe of non-EGU sources, makes it challenging to define a 
single method to identify appropriate control technologies, measures, 
or strategies and resulting impactful emissions reductions. Because of 
these challenges, the EPA adopted a different approach for assessing 
non-EGU NOX emissions reduction potential than the approach 
for EGUs described in the preceding section. To assess emissions 
reduction potential from non-EGUs, the EPA first performed a screening 
assessment to identify those industries that could have the greatest 
air quality impact at downwind receptors. This was followed by an 
assessment estimating annual NOX emissions reduction 
potential at specific cost thresholds for each of the most impactful 
industries. Next, the EPA estimated the reductions in ozone 
concentrations resulting from the emissions reductions for each 
industry in each of the 27 linked upwind states. As described later, 
the results indicate that the most impactful industries fall into two 
tiers based on the estimated reductions in ozone concentrations 
associated with the NOX emissions reductions.
    The Agency incorporated air quality information as a first step in 
an analytical framework to help determine potentially impactful 
industries to focus on for further assessing potential controls, 
emissions reduction potential, air quality improvements, and costs. The 
EPA developed the analytical framework using inputs from the air 
quality modeling for the Revised CSAPR Update for 2023,\161\ as well as 
the projected 2023 annual emissions inventory from the 2016v2 emissions 
platform that was used for the air quality modeling for this proposed 
rule. Additional information on the analytical framework is presented 
in the Non-EGU Screening Assessment memorandum available in the docket.
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    \161\ The EPA used the Revised CSAPR Update air quality modeling 
for this screening assessment because the air quality modeling for 
this proposed rule was not completed in time to support the 
assessment.
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    Using the Revised CSAPR Update modeling for 2023, the EPA 
identified upwind states linked to downwind nonattainment or 
maintenance receptors using the 1 percent of the NAAQS threshold 
criterion, which is 0.7 ppb (1 percent of a 70 ppb NAAQS). In 2023 
there were 27 linked states for the 2015 ozone NAAQS: Alabama, 
Arkansas, California, Delaware, Illinois, Indiana, Kentucky, Louisiana, 
Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New 
Jersey, New York, Ohio, Oklahoma, Oregon, Pennsylvania, Tennessee, 
Texas, Utah, Virginia, West Virginia, Wisconsin, and Wyoming.

[[Page 20083]]

    To analyze non-EGU emissions units, the EPA aggregated the 
underlying projected 2023 emissions inventory data into industries 
defined by 4-digit NAICS. Then for linked states, the EPA followed the 
2-step process below:
    Step 1--The EPA identified industries whose potentially 
controllable emissions have the greatest ppb impact on downwind air 
quality, and
    Step 2--The EPA determined which of the most impactful industries 
and emissions units had the most emissions reductions that would make 
meaningful air quality improvements at the downwind receptors at a 
marginal cost threshold the EPA determined using underlying control 
device efficiency and cost information.
    To estimate the contributions by industry, defined by 4-digit 
NAICS, at each downwind receptor the EPA used the 2023 state-receptor 
specific Revised CSAPR Update ppb/ton values and the Revised CSAPR 
Update calibration factors used in the air quality assessment tool 
(AQAT) for control analyses in 2023.\162\ The EPA focused on assessing 
emissions units that emit greater than 100 tons per year (tpy) of 
NOX.\163\ By limiting the focus to potentially controllable 
emissions, well-controlled sources that still emit greater than 100 tpy 
are excluded. Instead, the focus is on uncontrolled sources or sources 
that could be better controlled at a reasonable cost. As a result, 
reductions from any industry identified by this process are more likely 
to be achievable and to lead to air quality improvements.
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    \162\ The calibration factors are receptor-specific factors. For 
the Revised CSAPR Update, the calibration factors were generated 
using 2016 base case and 2023 base case air quality model runs. 
These receptor-level ppb/ton factors are discussed in the Ozone 
Transport Policy Analysis Final Rule TSD found here: https://www.epa.gov/sites/default/files/2021-03/documents/ozone_transport_policy_analysis_final_rule_tsd_0.pdf.
    \163\ In the non-EGU emissions reduction assessment prepared for 
the Revised Cross State Air Pollution Rule Update (https://www.regulations.gov/document/EPA-HQ-OAR-2020-0272-0014), The EPA 
reviewed emissions units with >150 tpy of NOX emissions. 
In this assessment, EPA broadened the scope to include emissions 
units with greater than or equal to 100 tpy of NOX 
emissions.
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    From this information, the EPA prepared a summary with the 
estimated total, maximum, and average contributions from each industry 
and the number of receptors with contributions greater than or equal to 
0.01 ppb from each industry.\164\ The EPA used this information to 
identify breakpoints in the data to determine which industries to focus 
on for the next steps in its analysis, as described in the Non-EGU 
Screening Assessment memorandum.
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    \164\ The EPA chose to include in the Non-EGU NOX 
reduction potential analysis those industries that contribute at 
least 0.01 ppb to a downwind receptor in order to focus the analysis 
on the most impactful industries. The 0.01 criterion is based on an 
analysis of the distribution and relative magnitude of contributions 
from 41 industries, as identified in the Non-EGU Screening 
Assessment memorandum. From this analysis the EPA determined that 
0.01 ppb provides a meaningful conservative breakpoint for screening 
out non-impactful industries from the Non-EGU analysis in this 
proposed rule. Details on this analysis that provides the basis for 
using 0.01 ppb can be found in the Non-EGU Screening Assessment 
memorandum.
---------------------------------------------------------------------------

    A review of the maximum contribution data indicated that the EPA 
should focus the assessment of NOX reduction potential and 
cost primarily on four industries. These industries each (1) have a 
maximum contribution to any one receptor of greater than 0.10 ppb and 
(2) contribute greater than or equal to 0.01 ppb to at least 10 
receptors. The four industries identified below comprise the ``Tier 1'' 
non-EGU industries.

 Pipeline Transportation of Natural Gas
 Cement and Concrete Product Manufacturing
 Iron and Steel Mills and Ferroalloy Manufacturing
 Glass and Glass Product Manufacturing

    In addition to these industries, the maximum contribution data 
suggests including five additional industries as a second tier in the 
assessment. These industries each either have (1) a maximum 
contribution to any one receptor greater than or equal to 0.10 ppb but 
contribute greater than or equal to 0.01 ppb to fewer than 10 
receptors, or (2) a maximum contribution less than 0.10 ppb but 
contribute greater than or equal to 0.01 ppb to at least 10 receptors. 
The five industries identified below comprise the ``Tier 2'' non-EGU 
industries.

 Basic Chemical Manufacturing
 Petroleum and Coal Products Manufacturing
 Metal Ore Mining
 Lime and Gypsum Product Manufacturing
 Pulp, Paper, and Paperboard Mills

    For additional discussion of the contribution information, see 
Appendix A of the Non-EGU Screening Assessment memorandum included in 
the docket for this proposed rulemaking.
    Next, to identify an annual cost threshold for evaluating potential 
emissions reductions in the Tier 1 and Tier 2 industries, the EPA used 
the Control Strategy Tool (CoST),\165\ the Control Measures Database 
(CMDB),\166\ and the projected 2023 emissions inventory to prepare a 
listing of potential control measures, and costs, applied to non-EGU 
emissions units in the projected 2023 emissions inventory. Using these 
data, the EPA plotted curves for Tier 1 industries, Tier 2 industries, 
Tier 1 and 2 industries, and all industries at $500 per ton increments. 
Figure 1 on page 4 of the Non-EGU Screening Assessment memorandum, 
which is available in the docket for this proposed rulemaking, 
indicates there is a ``knee in the curve'' at approximately $7,500 per 
ton (all non-EGU cost estimates in the assessment and presented in the 
rest of this section are in 2016 dollars). The EPA used this marginal 
cost threshold to further assess potential control strategies, 
estimated emissions reductions, air quality improvements, and costs 
from the potentially impactful industries. Note that controls and 
related emissions reductions are available at several estimated cost 
levels up to the $7,500 per ton threshold. (These costs do not include 
monitoring, recordkeeping, reporting, or testing costs.)
---------------------------------------------------------------------------

    \165\ Further information on CoST can be found at the following 
link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
    \166\ The CMDB is available at the following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
---------------------------------------------------------------------------

    Next, using the marginal cost threshold of $7,500 per ton, to 
estimate emissions reductions and costs the EPA processed the CoST run 
using the maximum emissions reduction algorithm,\167\ with known 
controls.\168\ The EPA identified controls for non-EGU emissions units 
in the Tier 1 and Tier 2 industries that cost up to $7,500 per ton. The 
EPA then calculated air quality impacts associated with the estimated 
reductions for the 27 linked states in 2023 using the following steps.
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    \167\ The maximum emissions reduction algorithm assigns to each 
source the single measure (if a measure is available for the source) 
that provides the maximum reduction to the target pollutant. For 
more information, see the CoST User's Guide available at the 
following link: https://www.cmascenter.org/cost/documentation/3.7/CoST%20User's%20Guide/.
    \168\ Known controls are well-demonstrated control devices and 
methods that are currently used in practice in many industries. 
Known controls do not include cutting edge or emerging pollution 
control technologies.
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    1. The EPA binned the estimated reductions by 4-digit NAICS code 
into the Tier 1 and Tier 2 industries.
    2. The EPA used the 2023 state-receptor specific Revised CSAPR 
Update ppb/ton values and the Revised CSAPR Update calibration factors 
used in the AQAT for control analyses in 2023. The EPA multiplied the 
estimated

[[Page 20084]]

non-EGU reductions by the ppb/ton values and by the receptor-specific 
calibration factor to estimate the ppb impacts from these emissions 
reductions.
    Next, because boilers represent the majority emissions units in the 
Tier 2 industries for which there were controls that cost up to $7,500 
per ton, the EPA further targeted emissions reductions and air quality 
improvements in Tier 2 industries by identifying potentially impactful 
industrial, commercial, and institutional (ICI) boilers. To identify 
potentially impactful boilers, using the projected 2023 emissions 
inventory in the linked upwind states, the EPA identified a universe of 
boilers with greater than 100 tpy NOX emissions that had 
contributions at downwind receptors.\169\ \170\ The EPA refined the 
universe of boilers to a subset of impactful boilers by sequentially 
applying the three criteria below to each boiler. This approach is 
similar to the overall analytical framework and was tailored for 
application to individual boilers.\171\
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    \169\ The EPA used the 2023fj non-EGU point source inventory 
files from the 2016v2 emissions platform.
    \170\ Maryland, Missouri, Nevada, and Wyoming did not have 
boilers with >100 tpy NOX emissions.
    \171\ For the impactful boiler assessment, the estimated air 
quality contributions and improvements were not based on modeling of 
individual emissions units or emissions source sectors. The air 
quality estimates were derived by using the 2023 state/receptor 
specific Revised CSAPR Update ppb/ton values and the Revised CSAPR 
Update calibration factors used in AQAT. The results indicate a 
level of precision not supported by the underlying air quality 
modeling. The results were intended to provide an indication of the 
relative impact across sources.
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     Criterion 1--Estimated maximum air quality contribution at 
an individual receptor of greater than or equal to 0.0025 ppb or 
estimated total contribution across downwind receptors of greater than 
or equal to 0.01 ppb.
     Criterion 2--Controls that cost up to $7,500 per ton.
     Criterion 3--Estimated maximum air quality improvement at 
an individual receptor of greater than or equal to 0.001 ppb.
    Lastly, the EPA updated its analytical framework to the 2026 
analytic year by which the EPA is proposing non-EGU controls be 
installed across the Tier 1 and Tier 2 industries and various emissions 
unit types. The EPA concluded, based on the most recent information 
available from the CSAPR Update Non-EGU TSD,\172\ that controls on all 
of the non-EGU emissions units cannot be installed by the 2023 ozone 
season. The EPA prepared the non-EGU screening assessment for the year 
2026 by generally applying the analytical framework detailed above, 
with some modifications. The updated screening assessment results for 
2026 are discussed in Section VI.C.2 \173\ of this proposed rule. 
Specifically, the EPA
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    \172\ Final Technical Support Document (TSD) for the Final 
Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment 
of Non-EGU NOX Emissions Controls, Cost of Controls, and 
Time for Compliance Final TSD (``CSAPR Update Non-EGU TSD''), August 
2016, available at https://www.epa.gov/csapr/assessment-non-egu-NOX-
emission-controls-cost-controls-and-time-compliance-final-tsd.
    \173\ The non-EGU screening assessment is not intended to be, 
nor take the place of, a unit-specific detailed engineering analysis 
that evaluates the feasibility of retrofits for the emissions units, 
potential controls, and related costs. For more detailed discussion 
of these issues, see Section VII.C of this proposed rule and the 
Non-EGU Sectors TSD included in the docket.
---------------------------------------------------------------------------

     Retained the impactful industries identified in Tier 1 and 
Tier 2, the $7,500 cost per ton threshold, and the methodology for 
identifying impactful boilers;
     Modified the framework to address challenges associated 
with using the projected 2023 emissions inventory by using the 2019 
emissions inventory; \174\ and
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    \174\ The EPA determined that the 2019 inventory was appropriate 
because it provided a more accurate prediction of potential near-
term emissions reductions. See the Non-EGU Screening Assessment 
memorandum, available in the docket, for a discussion of the 
challenges associated with using the projected 2023 emissions 
inventory.
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     Updated the air quality modeling data by using the most 
recent air quality modeling data for this proposal for the analytic 
year 2026.
3. Other Stationary Sources NOX Mitigation Strategies
    As part of its analysis for this proposed rule, the EPA also 
reviewed whether NOX mitigation strategies for any other 
stationary sources may be appropriate. In this section, the EPA 
discusses three classes of units that have historically been excluded 
from our interstate air transport programs: (1) Units less than or 
equal to 25 MW, (2) solid waste incineration units, and (3) 
cogeneration units. EPA's initial assessment does not lead it to 
propose inclusion of the units less than or equal to 25 MW, but the EPA 
is requesting comment on any particular units within this category that 
may offer cost-effective reduction potential. The EPA is also taking 
comment on and considering whether to include emissions limitations for 
solid waste incineration units (many of which are less than 25 MW) in a 
final rule, as discussed later. For cogeneration units previously 
exempted from EGU emissions budgets established through ozone 
interstate transport rules, the EPA has not identified a basis for 
inclusion in this proposal.
    The EPA has not historically identified substantial emissions 
reduction or air quality gains from corresponding reductions from these 
segments of units and has therefore not considered inclusion of these 
segments of stationary sources in its federal programs for interstate 
transport.
    However, given the need to implement a full remedy to address 
interstate transport, the more stringent 2015 ozone NAAQS of 70 ppb, 
and the extended period of time for which the EPA projects upwind 
contribution to persistent nonattainment and maintenance problems, the 
EPA is requesting comment on whether sources within these three 
segments--units serving a generator equal or smaller than 25 MW, 
cogeneration units, and solid waste incineration units--could merit 
inclusion within EPA's proposed NOX mitigation strategy in 
this rule. Specifically, the EPA requests comment on available 
NOX mitigation technologies, NOX emissions rate 
performance, total potentially available NOX reductions, 
installation timing, cost, air quality impacts, source-specific 
information, and any other information that could inform a control 
determination specific to these three types of units. The EPA provides 
an assessment of these three segments, their emissions control 
opportunities, and potential air quality benefits below. Additional 
considerations are further discussed in the EGU NOX 
Mitigation Strategies Proposed Rule TSD.
a. Units Less Than or Equal to 25 MW
    The EPA has historically not included control requirements for 
emissions for units less than or equal to 25 MW for three primary 
reasons: Low potential reductions, relatively high cost per ton of 
reduction, and high monitoring and other compliance burdens. In the 
January 11, 1993, Acid Rain permitting rule, the EPA provided for a 
conditional exemption from the emissions reduction, emitting, and 
emissions monitoring requirements of the Acid Rain Program for new 
units having a nameplate capacity of 25 MWe or less that burn fuels 
with a sulfur content no greater than 0.05% by weight, because of the 
de minimis nature of their potential SO2, CO2 and 
NOX emissions. See 63 FR 57484. The NOX SIP Call 
identified these as Small Point Sources. For the purposes of that 
rulemaking, the EPA considered electricity generating boilers and 
turbines serving a generator 25 MWe or less, to be small point sources. 
The EPA noted that the collective emissions from small sources

[[Page 20085]]

were relatively small and the administrative burden to the states and 
regulated entities of controlling such sources was likely to be 
considerable. As a result, the rule did not assume reductions from 
those sources in state emissions budgets requirements (63 FR 57402). 
Similar size thresholds have been incorporated in subsequent transport 
programs such as CAIR and CSAPR. As these sources were not identified 
as having cost-effective reductions and so were not included in those 
programs, they were also exempted from certain reporting requirements 
and the data for these sources is, therefore, not of the same caliber 
as that of covered larger sources.
    EPA's preliminary survey of current data, compared to this initial 
justification, does not appear to offer a compelling reason to depart 
from this past practice by requiring emission reductions from these 
small EGU sources as part of this rule. For instance, as explained in 
the EGU NOX Mitigation Strategies Proposed Rule TSD, EPA has 
evaluated the costs of SCR retrofits at small EGUs using its Retrofit 
Cost Analyzer and found that such controls become markedly less cost-
effective at lower levels of generating capacity. This analysis 
concluded that, after controlling for all other unit characteristics, 
the dollar per ton cost for a SCR retrofit increases by about a factor 
of 2.5 when moving from a 500 MW to a 10 MW unit, and a factor of 8 
when moving to a 1 MW unit.\175\ Moreover, the EPA estimates that under 
6% of nationwide EGU emissions come from units less than 25 MW and not 
covered by current applicability criteria due to this size exemption 
threshold. Therefore, the EPA is not proposing to require any emissions 
reductions from these units, but the EPA requests comment on whether 
there are any cost-effective reductions and corresponding air quality 
benefits to nonattainment or maintenance receptors from any units 
within this segment.
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    \175\ Preliminary estimate based on representative coal units 
with starting NOX rate of 0.2 lb/mmBtu, 10,000 BTU/kwh, 
and assuming 80 percent reduction.
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b. Municipal Solid Waste Units
    The EPA seeks comment on whether NOX emissions 
reductions should be sought from municipal solid waste combustor units 
(MWCs) to address interstate ozone transport. As noted below, MWCs emit 
substantial amounts of NOX, and some states have required 
emissions limits for these facilities that are more stringent than the 
federal requirements contained within EPA's new source performance 
standard (NSPS) for this industry. These more stringent limits, if 
applied broadly to the 26 states included in this proposed FIP action, 
would create an additional means of reducing NOX emissions.
    MWCs burn garbage and other non-hazardous solid material using a 
variety of combustion techniques. Section 2.1, Refuse Combustion, of 
the EPA emissions factor reference document AP-42 \176\ contains a 
description of the seven different combustion process technologies most 
commonly used in the industry. A copy of Section 2.1 of AP-42 is 
included within the Docket for this proposed rule. These seven 
combustion processes are as follows: Mass burn waterwall, mass burn 
rotary waterwall, mass burn refractory wall, refuse-derived fuel-fired, 
fluidized bed, modular starved air, and modular excess air. Section 2.1 
of AP-42 contains detailed process descriptions of each of these MWC 
processes. During the combustion process, a number of pollutants are 
produced, including NOX, which forms through oxidation of 
nitrogen in the waste and from fixation of nitrogen in the air used to 
burn the waste. NOX emissions from MWCs are typically 
released through tall stacks which enables the emissions to be 
transported long distances.
---------------------------------------------------------------------------

    \176\ ``AP-42, Fifth Edition Compilation of Air Pollutant 
Emissions Factors, Volume 1: Stationary Point and Area Sources'', 
available at: https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors.
---------------------------------------------------------------------------

    Most MWCs are cogeneration facilities that recover heat from the 
combustion process to power a turbine to produce electricity. According 
to a 2018 report from the Energy Recovery Council,\177\ 72 of the 75 
operating MWC facilities in the U.S. produce electricity from heat 
captured from the combustion process. The electrical output of MWCs is 
relatively small compared to the EGUs that will be regulated per the 
proposed requirements of Section VII.B of this proposal, with most MWCs 
having an electrical output capacity of less than 25 MW. The Non-EGU 
Sectors TSD located in the Docket identifies the electrical output 
capacity for MWC units that produce electricity as reflected in EPA's 
NEEDS database.
---------------------------------------------------------------------------

    \177\ ``2018 Directory of Waste to Energy Facilities''; Energy 
Recovery Council.
---------------------------------------------------------------------------

    However, despite their relatively small electricity-generating 
potential, NOX emissions from MWCs located in the transport 
states identified in this proposal are substantial. According to the 
EPA's NEI database, MWCs emitted 19,222 tons of NOX in 2017 
in the ten states included in this proposal that contain them. Table 8 
of the Non-EGU Sectors TSD contains a list of MWC facilities located 
within the states included in this proposal along with their 
NOX emissions as reported to the NEI.
    The EPA has promulgated NOX emissions limits for large 
MWCs, defined as those that process 250 tons of municipal solid waste 
per day or more at 40 CFR part 60, subpart Cb and 40 CFR part 60, 
subpart Eb. Subpart Cb is applicable to MWCs that commenced 
construction on or before September 20, 1994, while Subpart Eb is 
applicable to MWCs that commenced construction, modification, or 
reconstruction after September 20, 1994. The NOX limits for 
subpart Cb are found within Tables 1 and 2 of 40 CFR 60.39b and range 
from 165 to 250 ppm depending on the combustor design type. The 
NOX limits for Subpart Eb are found at 40 CFR 60.52b(d) and 
are 180 ppm during a unit's first year of operation and drop to 150 ppm 
afterwards, applicable across all combustor types. These limits 
correspond to NOX emissions rates of 0.31 and 0.26 lbs/
MMBtu, respectively.
    Section 182(b)(2) and (f) of the CAA requires states with ozone 
nonattainment areas classified as Moderate or higher to adopt 
regulations with control requirements representing reasonably available 
control technology (RACT) for major sources of VOCs and NOX. 
Sections 184(b)(1)(B) and 182(f) of the Act require RACT requirements 
be adopted in all areas included within the Ozone Transport Region 
(OTR). Due primarily to the NOX RACT requirement, many 
states within the Northeast located within the OTR have adopted 
NOX emissions limits for MWCs that are more stringent than 
what would otherwise be required by EPA's NSPS or the emissions 
guideline for these units. For example, the Montgomery County Resource 
Recovery Facility in Maryland is required to meet a NOX RACT 
limit of 140 ppm (at 7 percent oxygen) on a 24-hour block average. 
Additionally, MWC facilities located in Virginia operated by Covanta, 
Inc., are required to meet a NOX RACT limit of 110 ppm (at 7 
percent oxygen) on a 24-hour basis, and a limit of 90 ppm (at 7 percent 
oxygen) on an annual average basis.\178\ The 110 ppm limit equates to a 
limit of 0.19 lbs/MMBtu.
---------------------------------------------------------------------------

    \178\ The NOX permit limits for the Montgomery County 
facility and the Virginia facilities can be found within the OTC's 
Municipal Waste Combustor Workgroup Report included within the 
Docket for this proposed rule.
---------------------------------------------------------------------------

    The Ozone Transport Commission (OTC) issued a report entitled 
``Municipal Waste Combustor Workgroup Report'' in June of 2021. The

[[Page 20086]]

report is included within the docket for this proposal.\179\ The report 
notes that MWCs are a significant source of NOX emissions in 
the OTR, releasing approximately 22,000 tons of NOX from 
facilities within 9 OTR states in 2018. The report summarizes the 
results of a literature review of state-of-the-art NOX 
controls that have been successfully installed and concludes that 
significant reductions could be achieved using several different 
technologies described in the report, primarily via combustion 
modifications made to MWC units already equipped with SNCR. The MWC 
workgroup evaluated the emissions reduction potential from two 
different control levels, one based on a NOX concentration 
in the effluent of 105 to 110 ppm, and another based on a limit of 130 
ppm. The workgroup's findings were that a control level of 105 parts 
per million by volume, dry (ppmvd) on a 30-day average basis and a 110 
ppmvd on a 24-hour averaging period would reduce NOX 
emissions from MWCs by approximately 7,300 tons annually, and that a 
limit of 130 ppmvd on a 30 day-average could achieve a 4,000 ton 
reduction. The report notes that 8 MWC units exist that are already 
subject to permit limits of 110 ppm, 7 in Virginia, and one in Florida. 
Studies evaluating MWCs similar in design to the large MWCs in the OTR 
found NOX reductions could be achieved at costs ranging from 
$2,900 to $6,600 per ton of NOX reduced. Based on the 
findings of this report, the Commissioners of the states within the OTR 
adopted a resolution to develop a recommendation for emissions 
reductions from MWCs during their June 15, 2021, annual public 
meeting.\180\
---------------------------------------------------------------------------

    \179\ This report is also available at https://otcair.org/upload/Documents/Reports/20210624%20OTC%20SAS%20MWC%20report%20final.pdf.
    \180\ See ``Notice of Proposed rules Taken by Ozone Transport 
Commission At Annual Public Meeting, June 15, 2021'' included in the 
Docket for this proposed rule.
---------------------------------------------------------------------------

    In light of the above, the EPA requests comment on whether 
NOX limits for MWCs located in the states covered by this 
proposed rule should be included in the final FIP. Specifically, if 
NOX controls are included in the final FIP, the EPA requests 
comment on the following issues:
     What NOX emissions limit and averaging time 
should MWCs be required to meet, and in particular should the EPA adopt 
emissions rates of 105 ppmvd on a 30-day averaging basis and 110 ppmvd 
on a 24-hour averaging basis?
     What types of NOX control technology could be 
used to reduce NOX emissions at MWCs, and in particular 
should the EPA adopt the combustion control modifications made to units 
with previously installed SNCR identified by the MWC workgroup?
     Whether there is information that would call into question 
the OTC workgroup's estimated cost of controls for reducing 
NOX emissions from MWCs of $2,900 to $6,600 per ton, and, 
assuming that range is accurate, whether there is any justification for 
not requiring these controls in light of their relative cost-
effectiveness and total level of reductions available, which compare 
favorably with the proposed EGU and non-EGU control strategies?
     If the final FIP includes emissions reduction requirements 
for MWCs, should any mechanism be available by which a particular MWC 
source could seek to establish that meeting the required emissions 
limits is not feasible?
     Is there any evidence that retrofit of MWC emissions 
controls would take longer to implement than the 2026 ozone season?
     Would it be appropriate to rely on existing testing, 
monitoring, recordkeeping, and reporting requirements for MWCs under 
the applicable NSPS or other requirements?
c. Cogeneration Units
    Consistent with prior transport rules, fossil fuel-fired boilers 
and combustion turbines that produce both electricity and useful 
thermal energy (generally referred to as ``cogeneration units'') and 
that meet the applicability criteria to be included in the CSAPR 
NOX Ozone Season Group 3 Trading Program would be subject to 
the emissions reduction requirements established in this rulemaking for 
EGUs. However, those applicability criteria--which the EPA is not 
proposing to alter in this rulemaking (see Section VII.B.3 of this 
proposed rule)--exempt some cogeneration units from coverage as EGUs 
under the trading program. The EPA is proposing that fossil fuel-fired 
boilers and combustion turbines that produce both electricity and 
useful thermal energy and that do not meet the applicability criteria 
to be included in the CSAPR NOX Ozone Season Group 3 Trading 
Program as EGUs would not be subject to any other emissions reduction 
requirements under this rulemaking.
    Cogeneration systems can offer considerable environmental benefit 
as they often require less fuel to produce a given energy output. The 
average efficiency of fossil-fuel fired power plants in the United 
States is 33 percent. This means that two-thirds of the energy used to 
produce electricity at most power plants in the United States is wasted 
in the form of heat discharged to the atmosphere. By recovering wasted 
heat, combined heat and power (CHP) systems at cogeneration units 
typically achieve total system efficiencies of 60 to 80% for producing 
electricity and useful thermal energy. Some systems achieve 
efficiencies approaching 90%. This increased efficiency allows the same 
level of energy use to be achieved with fewer criteria-pollutant and 
greenhouse gas emissions. Additionally, these systems increase the 
reliability of access to electrical power for the facilities they serve 
and reduce the need for electricity from regional power plants and 
their associated transmission and distribution networks.
    According to information contained in the EPA's Combined Heat and 
Power Partnership's document ``Catalog of CHP Technologies'',\181\ 
there are 4,226 CHP installations in the U.S. providing 83,317 MWe of 
electrical capacity. Over 99% of the installations are powered by 5 
equipment types, those being reciprocating engines (52 percent), 
boilers/steam turbines (17 percent), gas turbines (16 percent), 
microturbines (8 percent), and fuel cells (4 percent). The majority of 
the electrical capacity is provided by gas turbine CHP systems (64 
percent) and boiler/steam turbine CHP systems (32 percent). The various 
CHP technologies described above are available in a large range of 
sizes, from as small as 1 kilowatt reciprocating engine systems to as 
large as 300 megawatt gas turbine powered systems.
---------------------------------------------------------------------------

    \181\ This document is available at: https://www.epa.gov/sites/default/files/2015-07/documents/catalog_of_chp_technologies.pdf.
---------------------------------------------------------------------------

    NOX emissions from fuel cell powered systems are 
negligible, and NOX emissions from rich-burn reciprocating 
engine, gas turbine, and microturbine systems are low, ranging from 
0.013 to 0.05 lbs/mmBTU. NOX emissions from lean-burn 
reciprocating engine systems and gas-powered steam turbines systems 
range from 0.1 to 0.2 lbs/mmBTU. The highest NOX emitting 
CHP units are solid fuel-fired boiler/steam turbine systems which emit 
NOX at rates ranging from 0.2 to 1.2 lbs/mmBTU. A 
preliminary assessment from EPA's IPM Summer 2021 Reference Case model 
suggest that cogeneration units exempted from current EPA EGU transport 
programs due to such classification are projected to account for 
approximately 5% of nationwide summer NOX emissions in 
2023.\182\
---------------------------------------------------------------------------

    \182\ https://www.epa.gov/airmarkets/results-using-epas-power-sector-modeling-platform-v6-summer-2021-reference-case. The EPA 
notes that cogeneration units not exempted from EGU Air programs are 
included in the EPA assessment of EGU reduction potential in Section 
VI.B.1 of this proposed rule.

---------------------------------------------------------------------------

[[Page 20087]]

    Under the proposed rule (consistent with prior CSAPR rulemakings), 
certain cogeneration units would be exempt from coverage under the 
CSAPR NOX Ozone Season Group 3 Trading Program as EGUs. 
Specifically, the trading program regulations include an exemption for 
a unit that qualifies as a cogeneration unit throughout the later of 
2005 or the first 12 months during which the unit first produces 
electricity and continues to qualify through each calendar year ending 
after the later of 2005 or that 12-month period and that meets the 
limitation on electricity sales to the grid. In order to meet the 
trading program's definition of ``cogeneration unit'' under the 
regulations, a unit (i.e., a fossil-fuel-fired boiler or combustion 
turbine) must be a topping-cycle or bottoming-cycle type that operates 
as part of a ``cogeneration system.'' A cogeneration system is defined 
as an integrated group of equipment at a source (including a boiler, or 
combustion turbine, and a generator) designed to produce useful thermal 
energy for industrial, commercial, heating, or cooling purposes and 
electricity through the sequential use of energy. A topping-cycle unit 
is a unit where the sequential use of energy results in production of 
useful power first and then, through use of reject heat from such 
production, in production of useful thermal energy. A bottoming-cycle 
unit is a unit where the sequential use of energy results in production 
of useful thermal energy first, and then, through use of reject heat 
from such production, in production of useful power. In order to 
qualify as a cogeneration unit, a unit also must meet certain 
efficiency and operating standards in 2005 and each year thereafter. 
The electricity sales limitation under the exemption is applied in the 
same way whether a unit serves only one generator or serves more than 
one generator. In both cases, the total amount of electricity produced 
annually by a unit and sold to the grid cannot exceed the greater of 
one-third of the unit's potential electric output capacity or 219,000 
MWh. This is consistent with the approach taken in the Acid Rain 
Program (40 CFR 72.7(b)(4)), where the cogeneration-unit exemption 
originated.
    The EPA is requesting comment on the proposal to exempt 
cogeneration units meeting the above criteria from any emissions 
reduction requirements under this proposed rulemaking. The EPA also 
requests comment on the alternative of requiring fossil fuel-fired 
boilers in the non-EGU industries identified earlier (Section VI.B.2.a 
of this proposed rule) that serve electricity generators and that 
qualify for an exemption from inclusion in the CSAPR NOX 
Ozone Season Group 3 Trading Program as EGUs to instead meet the same 
emissions standards, if any, that would apply under this proposed 
rulemaking to fossil fuel-fired boilers at facilities in the same non-
EGU industries that do not serve electricity generators. These proposed 
emissions standards are set forth in Section VII.C.5 of this proposed 
rule. Cogeneration units at these facilities are in the non-EGU 
industries identified in EPA's non-EGU screening assessment for this 
proposal (although potential emissions reductions from such 
cogeneration units were not specifically quantified in the assessment). 
Under this alternative approach, to the extent these industries have 
otherwise been determined in this proposal to significantly contribute 
to nonattainment or interfere with maintenance, the EPA would find that 
cogeneration units in these industries should not be excluded from 
EPA's overall NOX mitigation strategy.
4. Mobile Source NOX Mitigation Strategies
    Under a variety of CAA programs, the EPA has established federal 
emissions and fuel quality standards that reduce emissions from cars, 
trucks, buses, nonroad engines and equipment, locomotives, marine 
vessels, and aircraft (i.e., ``mobile sources''). Because states are 
generally preempted from regulating new vehicles and engines with 
certain exceptions (see generally CAA sections 209, 177), mobile source 
emissions are primarily controlled through EPA's federal programs. The 
EPA has been regulating mobile source emissions since it was 
established as a federal agency in 1970, and all mobile source sectors 
are currently subject to NOX emissions standards. The EPA 
factors these standards and associated emissions reductions into its 
baseline air quality assessment in good neighbor rulemaking, including 
in this proposed rule. These data are factored into EPA's analysis at 
Steps 1 and 2 of the 4-step framework. As a result of this long 
history, NOX emissions from onroad and nonroad mobile 
sources have substantially decreased (73 percent and 57 percent since 
2002, for onroad and nonroad, respectively) \183\ and are predicted to 
continue to decrease into the future as newer vehicles and engines that 
are subject to the most recent, stringent standards replace older 
vehicles and engines.\184\
---------------------------------------------------------------------------

    \183\ US EPA. Our Nation's Air: Status and Trends Through 2019. 
https://gispub.epa.gov/air/trendsreport/2020/#home.
    \184\ National Emissions Inventory Collaborative (2019). 2016v1 
Emissions Modeling Platform. Retrieved from http://views.cira.colostate.edu/wiki/wiki/10202.
---------------------------------------------------------------------------

    For example, in 2014, the EPA promulgated new, more stringent 
emissions and fuel standards for light-duty passenger cars and 
trucks.\185\ The fuel standards took effect in 2017, and the vehicle 
standards phase in between 2017 and 2025. Other EPA actions that are 
continuing to reduce NOX emissions include the Heavy-Duty 
Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control 
Requirements (66 FR 5002; January 18, 2001); the Clean Air Nonroad 
Diesel Rule (69 FR 38957; June 29, 2004); the Locomotive and Marine 
Rule (73 FR 25098; May 6, 2008); the Marine Spark-Ignition and Small 
Spark-Ignition Engine Rule (73 FR 59034; October 8, 2008); the New 
Marine Compression-Ignition Engines at or Above 30 Liters per Cylinder 
Rule (75 FR 22895; April 30, 2010); and the Aircraft and Aircraft 
Engine Emissions Standards (77 FR 36342; June 18, 2012).
---------------------------------------------------------------------------

    \185\ Control of Air Pollution from Motor Vehicles: Tier 3 Motor 
Vehicle Emissions and Fuel Standards, 79 FR 23414 (April 28, 2014).
---------------------------------------------------------------------------

    The EPA is currently developing a new regulatory effort to reduce 
NOX and other pollution from heavy-duty trucks (known as the 
Cleaner Trucks Initiative), as described in the January 21, 2020, 
Advance Notice of Proposed Rulemaking (85 FR 3306). Heavy-duty vehicles 
are the largest contributor to mobile source emissions of 
NOX and will be one of the largest mobile source 
contributors to ozone in 2025.\186\ Reducing heavy-duty vehicle 
emissions nationally would improve air quality where the trucks are 
operating as well as downwind. As required by CAA section 202(a)(3)(A) 
of the Act, the EPA will be proposing NOX emissions 
standards that ``reflect the greatest degree of emissions reduction 
achievable through the application of technology which the 
Administrator determines will be available for the model year to which 
such standards apply, giving appropriate consideration to cost, energy, 
and safety factors associated with the application of such 
technology.'' Section 202(a)(3)(C) of the Act requires that standards 
apply for no less than 3 model years and apply no earlier than 4 years 
after promulgation.
---------------------------------------------------------------------------

    \186\ Zawacki et al., 2018. Mobile source contributions to 
ambient ozone and particulate matter in 2025. Atmospheric 
Environment. Vol 188, pg 129-141. Available online: https://doi.org/10.1016/j.atmosenv.2018.04.057.
---------------------------------------------------------------------------

    The EPA's existing regulatory program for mobile sources will

[[Page 20088]]

continue to reduce NOX emissions into the future, and the 
EPA is currently taking active steps to ensure that these 
NOX reductions occur. The CAA prohibits tampering with 
emissions controls, as well as manufacturing, selling, and installing 
aftermarket devices intended to defeat those controls. The EPA 
currently has a National Compliance Initiative called ``Stopping 
Aftermarket Defeat Devices for Vehicles and Engines,'' which focuses on 
stopping the manufacture, sale, and installation of hardware and 
software specifically designed to defeat required emissions controls on 
onroad and nonroad vehicles and engines.

C. Control Stringencies Represented by Cost Threshold ($ per Ton) and 
Corresponding Emissions Reductions

1. EGU Emissions Reduction Potential by Cost Threshold
    For EGUs, as discussed in Section VI.A of this proposed rule, the 
multi-factor test considers increasing levels of uniform control 
stringency in combination with considering total NOX 
reduction potential and corresponding air quality improvements. The EPA 
evaluated EGU NOX emissions controls that are widely 
available (described previously in Section VI.B.1 of this proposed 
rule), that were assessed in previous rules to address ozone transport, 
and that have been incorporated into state planning requirements to 
address ozone nonattainment.
    The EPA evaluated the EGU sources within the state of California 
and found there were no covered coal steam sources greater than 100 MW 
that would have emissions reduction potential according to EPA's 
assumed EGU SCR retrofit mitigation technologies.\187\ The EGUs in the 
state are sufficiently well-controlled resulting in the lowest fossil-
fuel emission rate and highest share of renewable generation among the 
26 states examined at Step 3. EPA's Step 3 analysis, including analysis 
of the emissions reduction factors from EGU sources in the state, 
therefore resulted in no additional emission reductions required to 
eliminate significant contribution from any EGU sources in California.
---------------------------------------------------------------------------

    \187\ The only coal-fired power plant in California is the 63 MW 
Argus Cogeneration facility in Trona, California.
---------------------------------------------------------------------------

    The tables below summarize the emissions reduction potentials (in 
ozone season tons) from these emissions controls across the affected 
jurisdictions. Table VI.C.1-1 focuses on near-term emissions controls 
while Table VI.C.1-2 includes emissions controls with extended 
implementation timeframes.

                                     Table VI.C.1-1--EGU Ozone-Season Emissions and Reduction Potential (tons)--2023
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         Reduction potential (tons) for varying levels of technology inclusion
                                                              ------------------------------------------------------------------------------------------
                                                Baseline 2023                                                                     SCR/SNCR optimization
                    State                          OS NOX            SCR          SCR optimization +     SCR/SNCR optimization     + combustion control
                                                                optimization      combustion control      + combustion control    upgrades + generation
                                                                                      upgrades *                upgrades                 shifting
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................           6,648              32                      156                      156                      387
Arkansas.....................................           8,955              28                       28                       28                       66
Delaware.....................................             423              35                       35                       39                       35
Illinois.....................................           7,662              70                       70                      247                      120
Indiana......................................          12,351             856                      856                      865                    1,191
Kentucky.....................................          13,900             446                    1,047                    1,047                    2,260
Louisiana....................................           9,987             579                      579                      675                      579
Maryland.....................................           1,208               0                        0                        8                       13
Michigan.....................................          10,737               4                        4                       19                        4
Minnesota....................................           4,207              98                       98                      139                      246
Mississippi..................................           5,097              73                      697                      697                      697
Missouri.....................................          20,094           7,345                    7,345                    7,569                    8,013
Nevada.......................................           2,346              66                       66                       66                       66
New Jersey...................................             915             105                      105                      105                      116
New York.....................................           3,927              64                       64                       64                      164
Ohio.........................................          10,295           1,161                    1,161                    1,161                    1,926
Oklahoma.....................................          10,463             199                      890                      890                      890
Pennsylvania.................................          12,242           2,878                    2,878                    2,978                    3,287
Tennessee....................................           4,319             110                      110                      110                       85
Texas........................................          40,860             921                      921                    1,154                    2,344
Utah.........................................          15,500               7                        7                        7                      519
Virginia.....................................           3,415             164                      242                      296                      271
West Virginia................................          14,686             554                    1,099                    1,380                    1,927
Wisconsin....................................           5,933               7                        7                       26                      -50
Wyoming......................................          10,191              82                      677                      690                    1,648
                                              ----------------------------------------------------------------------------------------------------------
    Total....................................         236,363          15,883                   19,143                   20,417                   26,806
--------------------------------------------------------------------------------------------------------------------------------------------------------
* The EPA shows reduction potential from state-of-the-art LNB upgrade as near-term reduction emissions controls, but explains in Section VI.B and VI.D
  of this proposed rule that this reduction potential would not be implemented until 2024 for states not included in the Revised CSAPR Update.


[[Page 20089]]


                                     Table VI.C.1-2--EGU Ozone-Season Emissions and Reduction Potential (tons)--2026
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Reduction potential (tons) for varying levels of technology inclusion
                                              ----------------------------------------------------------------------------------------------------------
                                                                     SCR                                                          SCR/SNCR optimization
            State               Baseline 2026                   optimization    SCR/SNCR optimization    SCR/SNCR optimization    + combustion  control
                                   OS NOX            SCR        + combustion     + combustion control     + combustion control     upgrades  + SCR/SNCR
                                                optimization       control             upgrades           upgrades + SCR/SNCR     retrofits + generation
                                                                  upgrades                                     retrofits                 shifting
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................           6,701              32             156                      156                      916                      916
Arkansas.....................           8,728              28              28                       28                    4,697                    4,805
Delaware.....................             473              35              35                       39                       39                       39
Illinois.....................           7,763              70              70                      247                    1,298                    1,648
Indiana......................           9,737             720             720                      729                    1,740                    1,946
Kentucky.....................          13,211             446             885                      885                    5,450                    5,638
Louisiana....................           9,854             579             579                      675                    6,102                    6,102
Maryland.....................           1,208               0               0                        8                        8                       19
Michigan.....................           9,129               4               4                       19                    2,959                    3,015
Minnesota....................           4,197              98              98                      139                    1,613                    1,661
Mississippi..................           5,077              73             697                      697                    3,164                    3,163
Missouri.....................          18,610           7,345           7,345                    7,569                   11,237                   11,364
Nevada.......................           2,438              66              66                       66                    1,227                    1,227
New Jersey...................             915             105             105                      105                      105                      116
New York.....................           3,927              64              64                       64                      589                      689
Ohio.........................          10,295           1,161           1,161                    1,161                    1,354                    1,709
Oklahoma.....................          10,283             199             890                      890                    5,968                    6,008
Pennsylvania.................          11,738           2,737           2,737                    2,837                    4,510                    4,919
Tennessee....................           4,064              81              81                       81                       81                       81
Texas........................          39,186             921             921                    1,154                   15,817                   17,240
Utah.........................           9,679               7               7                        7                    7,076                    7,059
Virginia.....................           3,243             164             242                      263                      646                      676
West Virginia................          14,686             554           1,099                    1,380                    3,660                    4,089
Wisconsin....................           3,628               7               7                       26                       54                      155
Wyoming......................          10,249              82             677                      690                    5,669                    5,759
                              --------------------------------------------------------------------------------------------------------------------------
    Total....................         219,017          15,577          18,675                   19,917                   85,978                   90,041
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. Non-EGU Emissions Reduction Potential--Cost Threshold Up to $7,500/
ton
    The EPA used the updated non-EGU screening assessment for 2026 to 
estimate emissions reduction potential from the Tier 1 and Tier 2 
industries and non-EGU emissions units. The EPA used CoST to identify 
emissions units, emissions reductions, and associated compliance costs 
to evaluate the effects of potential non-EGU emissions control measures 
and technologies. CoST is designed to be used for illustrative control 
strategy analyses (e.g., NAAQS regulatory impact analyses) and not for 
unit-specific, detailed engineering analyses. These estimates from CoST 
identify proxies for (1) non-EGU emissions units that have emissions 
reduction potential, (2) potential controls for and emissions 
reductions from these emissions units, and (3) control costs from the 
potential controls on these emissions units. The cost estimates do not 
include monitoring, recordkeeping, reporting, or testing costs.
    To prepare the non-EGU screening assessment for 2026, the EPA 
applied the analytical framework detailed in Section VI.B.2 of this 
proposed rule. The assessment includes emissions units from the Tier 1 
industries and impactful high-emitting boilers in Tier 2 Industries. 
Using the latest air quality modeling for 2026, the EPA identified 
upwind states linked to downwind nonattainment or maintenance receptors 
using the 1% of the NAAQS threshold criterion, or 0.7 ppb. In 2026 
there are 23 linked states for the 2015 ozone NAAQS: Arkansas, 
California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming.
    The EPA re-ran CoST with known controls, the CMDB, and the 2019 
emissions inventory.\188\ The EPA specified CoST to allow replacing an 
existing control if a replacement control is estimated to be greater 
than 10% more effective than the existing control. The EPA did not 
replace an existing control if the 2019 emissions inventory indicated 
the presence of that control, even if the CMDB reflects a greater 
control efficiency for that control. Also, the EPA removed six 
facilities from consideration because they are subject to an existing 
consent decree, are shut down, or will shut down by 2026. For 
additional detail on the six facilities removed, see Appendix B in the 
Non-EGU Screening Assessment memorandum. Table VI.C.2-1 summarizes the 
estimated reductions, total ppb improvements across all receptors, and 
annual total and average annual costs (in 2016 dollars) and Table 
VI.C.2-2 below summarizes the estimated reductions by state.
---------------------------------------------------------------------------

    \188\ The EPA determined that the 2019 inventory was appropriate 
because it provided a more accurate prediction of potential near-
term non-EGU emissions reductions.

[[Page 20090]]



 Table VI.C.2-1--Estimated Emissions Reductions (Ozone Season Tons), Total PPB Improvements Across All Downwind
                                              Receptors, and Costs
----------------------------------------------------------------------------------------------------------------
                                                             Total PPB                          Industries (# of
                                                            improvement    Annual total cost    emissions units
             Tier                Ozone season emissions     across all      (million 2016$)       >100 tpy in
                                 reductions (East/West)      downwind       (average annual        identified
                                                             receptors         cost/ton)          industries)
----------------------------------------------------------------------------------------------------------------
Tier 1 Industries with Known       41,153 (37,972/3,181)           4.352      $356.6 ($3,610)  Cement and
 Controls that Cost up to                                                                       Concrete Product
 $7,500/ton.                                                                                    Manufacturing
                                                                                                (47) Glass and
                                                                                                Glass Product
                                                                                                Manufacturing
                                                                                                (44) Iron and
                                                                                                Steel Mills &
                                                                                                Ferroalloy
                                                                                                Manufacturing
                                                                                                (39) Pipeline
                                                                                                Transportation
                                                                                                of Natural Gas
                                                                                                (307).
Tier 2 Industry Boilers with            6,033 (5,965/68)           0.809         54.2 (3,744)  Basic Chemical
 Known Controls that Cost up                                                                    Manufacturing
 to $7,500/ton.                                                                                 (17) Petroleum
                                                                                                and Coal
                                                                                                Products
                                                                                                Manufacturing
                                                                                                (10) Pulp Paper,
                                                                                                and Paperboard
                                                                                                Mills (25).
----------------------------------------------------------------------------------------------------------------


             Table VI.C.2-2--Estimated Emissions Reductions (Ozone Season Tons) by Upwind State * **
----------------------------------------------------------------------------------------------------------------
                                                                 2019 OS NOX emissions
                             State                                                          OS NOX reductions
----------------------------------------------------------------------------------------------------------------
AR............................................................                    8,265                    1,654
CA............................................................                   14,579                    1,666
IL............................................................                   16,870                    2,452
IN............................................................                   19,604                    3,175
KY............................................................                   11,934                    2,291
LA............................................................                   35,831                    6,769
MD............................................................                    2,365                       45
MI............................................................                   18,996                    2,731
MN............................................................                   17,591                      673
MO............................................................                    9,109                    3,103
MS............................................................                   12,284                    1,761
NJ............................................................                    2,025                        0
NV............................................................                    2,418                        0
NY............................................................                    6,003                      500
OH............................................................                   19,729                    2,790
OK............................................................                   22,146                    3,575
PA............................................................                   15,861                    3,284
TX............................................................                   47,135                    4,440
UT............................................................                    6,276                      757
VA............................................................                    7,041                    1,563
WI............................................................                    6,571                    2,150
WV............................................................                    9,825                      982
WY............................................................                   10,335                      826
                                                               -------------------------------------------------
    Total.....................................................                  322,793                   47,187
----------------------------------------------------------------------------------------------------------------
* In the non-EGU screening assessment, EPA estimated emissions reduction potential from the non-EGU industries
  and emissions units. The estimated emissions reductions by state in the table above are from the non-EGU
  screening assessment; for additional results from the non-EGU screening assessment, including estimated
  reductions by state and by industry, please see the Non-EGU Screening Assessment memorandum available in the
  docket.
** In the assessment, EPA used CoST to identify emissions units, emissions reductions, and associated compliance
  costs to evaluate the effects of potential non-EGU emissions control measures and technologies. CoST is
  designed to be used for illustrative control strategy analyses (e.g., NAAQS regulatory impact analyses) and
  not for unit-specific, detailed engineering analyses. These estimates from CoST identify proxies for (1) non-
  EGU emissions units that have emissions reduction potential, (2) potential controls for and emissions
  reductions from these emissions units, and (3) control costs from the potential controls on these emissions
  units. The cost estimates do not include monitoring, recordkeeping, reporting, or testing costs.

    In this section, EPA provides a summary of the control technologies 
applied and their average costs across all of the non-EGU emissions 
units included in the screening assessment. This summary reflects one 
approach to organizing this information, which the Agency finds 
reasonable based on the information available for this proposal. As 
discussed in Section VI.B.2 of this proposed rule, the number of 
different industries and emissions unit categories and types present a 
challenge to defining a single method to identify appropriate control 
technologies, measures or strategies, and related costs across non-EGU 
emissions units. Because of the number of industries and emissions unit 
types, the available information does not easily allow grouping 
estimated emissions reductions by cost per ton threshold for a few 
control technologies, measures, or strategies. Nonetheless, Table 
VI.C.2-3 below provides a summary of estimated reductions and average 
cost per ton values by control technology across all non-EGU emissions 
units included in the non-EGU screening assessment. The summary 
reflects fourteen control technologies applied by CoST across all 
emissions units in the non-EGU screening assessment. The average cost 
per ton values range from $585 to $6,300 per ton, all of which are 
below the marginal cost per ton threshold of $7,500 per ton. Note that 
the average cost per ton values are in 2016 dollars and reflect simple 
averages and not a percentile or other representative cost values from 
a distribution of cost estimates.
    The Non-EGU Screening Assessment memorandum includes two other 
summaries of estimated reductions and average cost per ton values by 
technology across non-EGU emissions units. First, the memorandum 
includes a summary by control technology as applied across non-EGU 
emissions units grouped by the Tier 1 industries and

[[Page 20091]]

impactful boilers in Tier 2 industries, which given this further 
disaggregation reflects 18 control technologies across the tiers 
applied by CoST. Second, the memorandum includes a summary by control 
technology across non-EGU emissions units grouped by the seven 
individual Tier 1 and 2 industries, which given this disaggregation 
reflects 26 control technologies across the industries applied by CoST.

 Table VI.C.2-3--Estimated Emissions Reductions (Ozone Season Tons), Annual Total Cost, and Average Cost per Ton
                            by Control Technology Across All Non-EGU Emissions Units
----------------------------------------------------------------------------------------------------------------
                                                                 Ozone season emissions
                      Control technology                               reductions          Average cost per ton
----------------------------------------------------------------------------------------------------------------
Adjust Air to Fuel Ratio and Ignition Retard..................                      212                   $2,393
Layered Combustion............................................                   12,706                    5,457
Low NOX Burner................................................                      231                    3,773
Low NOX Burner and Flue Gas Recirculation.....................                      200                    4,288
Natural Gas Reburn............................................                      284                    2,703
Non-Selective Catalytic Reduction.............................                      147                      585
Non-Selective Catalytic Reduction or Layered Combustion.......                    6,359                    4,743
Oxygen Enriched Air Staging...................................                       52                      764
SCR + DLN Combustion..........................................                      136                    6,301
Selective Catalytic Reduction.................................                   12,239                    2,543
Selective Catalytic Reduction and Steam Injection.............                      929                    3,787
Selective Non-Catalytic Reduction.............................                    8,076                    1,485
Ultra-Low NOX Burner..........................................                    1,670                    2,890
Ultra-Low NOX Burner and Selective Catalytic Reduction........                    3,946                    4,114
----------------------------------------------------------------------------------------------------------------

    Refer to the Non-EGU Screening Assessment memorandum for additional 
2026 screening assessment results--including by industry and by state, 
estimated emissions reductions and costs, as well as by industry, 
emissions source groups, control technologies, number of emissions 
units, estimated ozone season reductions, and annual total cost.

D. Assessing Cost, EGU and Non-EGU NOX Reductions, and Air Quality

    To determine the emissions that are significantly contributing to 
nonattainment or interfering with maintenance, the EPA applied the 
multi-factor test to EGUs and non-EGUs separately, considering for each 
the relationship of cost, available emissions reductions, and downwind 
air quality impacts. Specifically, for each sector, the EPA proposes a 
determination regarding the appropriate level of uniform NOX 
control stringency that would collectively eliminate significant 
contribution to downwind nonattainment and maintenance receptors. The 
EPA also evaluated whether the proposed rule resulted in possible over-
control scenarios by evaluating if an upwind state is linked solely to 
downwind air quality problems that could have been resolved at a lower 
cost threshold, or if an upwind state could have reduced its emissions 
below the 1 percent air quality contribution threshold at a lower cost 
threshold.
1. EGU Assessment
    For EGUs, the EPA examined the emissions reduction potential 
associated with each EGU emissions control technology (presented in 
Section VI.C.1 of this proposed rule) and its impact on the air quality 
at downwind receptors. Specifically, EPA identified and assessed the 
projected average air quality improvements relative to the base case 
and whether these improvements are sufficient to shift the status of 
receptors from projected nonattainment to maintenance or from 
maintenance to attainment. Combining these air quality factors, costs, 
and emissions reductions, the EPA identified a control stringency for 
EGUs that results in substantial air quality improvement from emissions 
controls that are available in the timeframe for which air quality 
problems at downwind receptors persist. For all affected jurisdictions, 
this control stringency reflects, at a minimum, the optimization of 
existing post-combustion controls and installation of state-of-the-art 
NOX combustion controls, which are widely available at a 
representative marginal cost of $1,800 per ton. EPA's evaluation also 
shows that the effective emissions rate performance across affected 
EGUs consistent with realization of these mitigation measures does not 
over-control upwind states' emissions relative to either the downwind 
air quality problems to which they are linked at Step 1 or the 1 
percent contribution threshold that triggers further evaluation at Step 
3 of the 4-step framework for the 2015 ozone NAAQS.
    Similarly, the EPA also identified installation of new SCR post-
combustion controls at coal steam sources greater than or equal to 100 
MW and for a more limited portion of the oil/gas steam fleet that had 
higher levels of emissions as components of the required control 
stringency. These SCR retrofits are widely available by the 2026 ozone 
season at $11,000 and $7,700 per ton respectively. For all but 3 of the 
affected states (Alabama, Delaware, and Tennessee--which are no longer 
linked in 2026 at Steps 1 and 2 in EPA's base case air quality 
modeling), EPA's evaluation also shows that the effective emissions 
rate performance across EGUs consistent with realization of these 
mitigation measures does not over-control upwind states' emissions in 
2026 relative to either the downwind air quality problems to which they 
are linked at Step 1 or the 1 percent contribution threshold that 
triggers further evaluation at Step 3 of the 4-step framework for the 
2015 ozone NAAQS (see the Ozone Transport Policy Analysis Proposed Rule 
TSD for details).
    To assess downwind air quality impacts for the nonattainment and 
maintenance receptors identified in Section V.D of this proposed rule, 
the EPA evaluated the air quality change at that receptor expected from 
the progressively more stringent upwind EGU control stringencies that 
were available for that time period in upwind states linked to that 
receptor. This assessment provides the downwind ozone improvements for 
consideration and provides air quality data that is

[[Page 20092]]

used to evaluate potential over-control situations.
    To assess the air quality impacts of the various control 
stringencies at downwind receptors for the purposes of Step 3, the EPA 
evaluated changes resulting from the emissions reductions associated 
with the identified emissions controls in each of the upwind states, as 
well as assumed corresponding reductions of similar stringency in the 
downwind state containing the receptor to which they are linked. By 
applying these emissions reductions to the state containing the 
receptor, the EPA assumes that the downwind state will implement (if it 
has not already) an emissions control stringency for its sources that 
is comparable to the upwind control stringency identified here. 
Consequently, The EPA is accounting for the downwind state's share of a 
nonattainment or maintenance problem as a part of the over-control 
evaluation.\189\
---------------------------------------------------------------------------

    \189\ For EGUs, this analysis for the Connecticut receptors 
shows no EGU reduction potential from the emissions reduction 
measures identified given that state's already low-emitting fleet; 
however, EGU reductions were identified in Colorado and these 
reductions were included in the over-control analysis.
---------------------------------------------------------------------------

    For this assessment, the EPA used an ozone air quality assessment 
tool (ozone AQAT) to estimate downwind changes in ozone concentrations 
related to upwind changes in emissions levels. The EPA focused its 
assessment on the years 2023 and 2026 as they pertain to the last years 
for which ozone season emissions data can be used for purposes of 
determining attainment for the Moderate (2024) and Serious (2027) 
attainment dates. For each EGU emissions control technology, the EPA 
first evaluated the magnitude of the change in ozone concentrations at 
the nonattainment and maintenance receptors for each relevant year 
(i.e., 2023 and 2026). Next, the EPA evaluated whether the estimated 
change in concentration would resolve the receptor's nonattainment or 
maintenance concern by lowering the average or maximum design values, 
respectively, below 71 ppb. For a complete set of estimates, see the 
Ozone Transport Policy Analysis Proposed Rule TSD or the ozone AQAT 
excel file.
    For 2023, the EPA evaluated potential air quality improvements at 
the downwind receptors outside of California associated with available 
EGU emissions control technologies in that timeframe. The EPA 
determined for the purposes of Step 3 that the average air quality 
improvement at the receptors relative to the engineering analytics base 
case was 0.11 ppb for emissions reductions commensurate with 
optimization of existing SCRs/SNCRs and combustion control upgrades. 
The EPA determined for the purposes of Step 3 that one receptor in 
Clark County, Nevada switches from maintenance to attainment with these 
mitigation strategies in place. Table VI.D.1-1 summarizes the results 
of EPA's Step 3 evaluation of air quality improvements at these 
receptors using AQAT.
    For 2026, the EPA determined that the average air quality 
improvement at these receptors relative to the engineering analytics 
base case was 0.43 ppb for emissions reductions commensurate with 
optimization of existing SCRs/SNCRs, combustion control upgrades, and 
new post-combustion control (SCR and SNCR) retrofits at eligible units 
are assumed to be implemented. The EPA determined for the purposes of 
Step 3 that in 2026, all but one of the receptors are expected to 
remain nonattainment or maintenance across these control stringencies, 
with one receptor in Douglas County, Colorado switching from 
maintenance to attainment with these mitigation strategies in 
place.\190\ Table VI.D.1-2 summarizes the results of EPA's Step 3 
evaluation of air quality improvements at the receptors included in the 
AQAT analysis. For more information about how this assessment was 
performed and the results of the analysis for each receptor, refer to 
the Ozone Transport Policy Analysis Proposed Rule TSD and to the Ozone 
AQAT included in the docket for this rule.
---------------------------------------------------------------------------

    \190\ As in prior rules, for the purpose of defining significant 
contribution at Step 3, the EPA evaluated air quality changes 
resulting from the application of the emissions reductions in only 
those states that are linked to each receptor as well as the state 
containing the receptor. By applying reductions to the state 
containing the receptor, the EPA ensures that it is accounting for 
the downwind state's fair share. This method holds each upwind state 
responsible for its fair share of the downwind problems to which it 
is linked. Reductions made by other states in order to address air 
quality problems at other receptors do not increase or decrease this 
share. The air quality impacts on design values that reflect the 
emissions reductions in all linked states and the health and climate 
benefits from this proposal are discussed in Section IX of this 
proposed rule.

                         Table VI.D.1-1--Air Quality at the 29 Receptors in 2023 From EGU Emissions Control Technologies \a\ \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Average DV  (ppb)                        Max DV  (ppb)
                                                                            ----------------------------------------------------------------------------
          Monitor ID No.                  State                County            Baseline         SCR/SNCR          Baseline
                                                                               (engineering    optimization +     (engineering   SCR/SNCR optimization +
                                                                                analysis)        LNB upgrade       analysis)            LNB upgrade
--------------------------------------------------------------------------------------------------------------------------------------------------------
040278011........................  Arizona............  Yuma...............            70.53            70.53             72.25                    72.24
080350004........................  Colorado...........  Douglas............            72.35            72.28             72.96                    72.89
080590006........................  Colorado...........  Jefferson..........            73.23            73.19             73.84                    73.80
080590011........................  Colorado...........  Jefferson..........            74.41            74.38             75.13                    75.09
090010017........................  Connecticut........  Fairfield..........            73.11            73.14             73.82                    73.85
090013007........................  Connecticut........  Fairfield..........            74.45            74.44             75.37                    75.36
090019003........................  Connecticut........  Fairfield..........            76.30            76.29             76.51                    76.50
090099002........................  Connecticut........  New Haven..........            72.11            72.07             74.16                    74.12
170310001........................  Illinois...........  Cook...............            70.02            70.02             73.90                    73.89
170310032........................  Illinois...........  Cook...............            70.14            70.15             72.78                    72.79
170310076........................  Illinois...........  Cook...............            69.64            69.65             72.49                    72.49
170314201........................  Illinois...........  Cook...............            70.19            70.18             73.75                    73.74
170317002........................  Illinois...........  Cook...............            70.42            70.33             73.37                    73.29
320030075........................  Nevada.............  Clark..............            70.09            70.06             71.01                    70.98
420170012........................  Pennsylvania.......  Bucks..............            71.09            71.03             72.63                    72.57
480391004........................  Texas..............  Brazoria...........            71.71            71.29             73.89                    73.45
481210034........................  Texas..............  Denton.............            71.20            71.03             73.06                    72.89
482010024........................  Texas..............  Harris.............            76.92            76.55             78.48                    78.10
482010055........................  Texas..............  Harris.............            72.50            72.14             73.54                    73.17
482011034........................  Texas..............  Harris.............            72.07            71.67             73.32                    72.91
482011035........................  Texas..............  Harris.............            69.69            69.31             73.32                    72.92
490110004........................  Utah...............  Davis..............            73.65            73.59             75.91                    75.85

[[Page 20093]]

 
490353006........................  Utah...............  Salt Lake..........            74.35            74.29             75.99                    75.93
490353013........................  Utah...............  Salt Lake..........            75.27            75.21             75.78                    75.72
490570002........................  Utah...............  Weber..............            71.35            71.29             73.29                    73.23
490571003........................  Utah...............  Weber..............            71.24            71.19             72.16                    72.11
550590019........................  Wisconsin..........  Kenosha............            73.17            73.07             74.09                    73.99
550590025........................  Wisconsin..........  Kenosha............            69.62            69.46             72.69                    72.52
551010020........................  Wisconsin..........  Racine.............            71.70            71.61             73.64                    73.55
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average AQ Change Relative to Base (ppb).......................................................................................                     0.11
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total PPB Change Across All Receptors Relative to Base \c\.....................................................................                     3.08
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ These results reflect the inclusion of all identified LNB upgrade potential. Some of which will be implemented in 2023 state emissions budgets, and
  some be implemented in 2024 state emissions budgets (for those states not included in the Revised CSAPR Update).
\b\ The EPA notes that the design values reflected in tables VI.D.1-1 and 2 correspond to the engineering analysis EGU emissions inventory that was used
  in AQAT to determine state-level baseline emissions and reductions at Step 3. These tools are discussed in greater detail in the Ozone Transport
  Policy Analysis Proposed Rule TSD.
\c\ The cumulative ppb change only shows the aggregate change across all problematic receptors (some of which are located within close proximity to one
  another) in this part of the Step 3 analysis. Section IX of this proposed rule provides a more complete picture of the air quality impacts of the
  proposed rule.


                                Table VI.D.1-2--Air Quality at Receptors in 2026 From EGU Emissions Control Technologies
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Average DV  (ppb)                        Max DV  (ppb)
                                                                            ----------------------------------------------------------------------------
                                                                                                  SCR/SNCR
          Monitor ID No.                  State                County            Baseline      optimization  +      Baseline      SCR/SNCR optimization
                                                                               (engineering     LNB upgrade +     (engineering    + LNB upgrade +  SCR/
                                                                                analysis)         SCR/SNCR         analysis)          SNCR retrofit
                                                                                                  retrofit
--------------------------------------------------------------------------------------------------------------------------------------------------------
40278011.........................  Arizona............  Yuma...............            70.11            70.09             71.81                    71.79
80350004.........................  Colorado...........  Douglas............            70.94            70.23             71.55                    70.83
80590006.........................  Colorado...........  Jefferson..........            72.09            71.42             72.69                    72.02
80590011.........................  Colorado...........  Jefferson..........            72.97            72.32             73.68                    73.02
90010017.........................  Connecticut........  Fairfield..........            71.60            71.52             72.30                    72.22
90013007.........................  Connecticut........  Fairfield..........            73.09            72.84             73.99                    73.74
90019003.........................  Connecticut........  Fairfield..........            74.83            74.63             75.03                    74.83
90099002.........................  Connecticut........  New Haven..........            70.77            70.51             72.78                    72.51
170310001........................  Illinois...........  Cook...............            69.05            68.96             72.87                    72.77
170310032........................  Illinois...........  Cook...............            69.37            69.32             71.98                    71.93
170310076........................  Illinois...........  Cook...............            68.75            68.71             71.56                    71.52
170314201........................  Illinois...........  Cook...............            69.10            69.02             72.61                    72.53
170317002........................  Illinois...........  Cook...............            69.36            69.18             72.27                    72.09
480391004........................  Texas..............  Brazoria...........            70.93            69.35             73.09                    71.46
482010024........................  Texas..............  Harris.............            76.28            74.77             77.82                    76.28
490110004........................  Utah...............  Davis..............            72.20            71.61             74.42                    73.81
490353006........................  Utah...............  Salt Lake..........            73.00            72.40             74.61                    74.00
490353013........................  Utah...............  Salt Lake..........            74.10            73.45             74.60                    73.95
490570002........................  Utah...............  Weber..............            70.30            69.74             72.22                    71.64
550590019........................  Wisconsin..........  Kenosha............            72.01            71.80             72.91                    72.70
550590025........................  Wisconsin..........  Kenosha............            68.46            68.19             71.48                    71.19
551010020........................  Wisconsin..........  Racine.............            70.52            70.33             72.42                    72.24
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average AQ Change Relative to Base (ppb).......................................................................................                     0.43
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total PPB Change Across All Receptors Relative to Base (ppb)...................................................................                     9.42
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Figures 1 and 2 to Section VI.D.1, included in Appendix G of the 
Ozone Transport Policy Analysis Proposed Rule TSD available in the 
docket for this rulemaking, illustrate the air quality improvement 
relative to the estimated representative cost associated with the 
previously identified emissions control technologies. The graphs show 
improving air quality at the downwind receptors as emissions reductions 
commensurate with the identified control technologies are assumed to be 
implemented. Figure 1 to Section VI.D.1 \191\ reflects emissions 
reductions commensurate with optimization of existing SNCRs and SCRs. 
Figure 2 to Section VI.D.1 \192\ reflects emissions reductions 
commensurate with installation of new post combustion controls (mainly 
SCRs) layered on top of the emissions reduction potential from the 
technologies represented in Figure 1 to Section VI.D.1.\193\ The 
graphic, and underlying AQAT receptor-by-receptor analysis demonstrates 
that air quality continues to improve at downwind receptors as EPA 
examines increasingly stringent EGU NOX control

[[Page 20094]]

technologies. While all major technology breakpoints identified in 
Sections VI.B and VI.C of this proposed rule show continued air quality 
improvements at problematic receptors and at cost and technology choice 
levels that are commensurate with mitigation strategies that are proven 
to be widely available and implemented, EPA's quantification and 
application of those breakpoints reflect certain exclusions to: (1) 
Preserve this consistency with widely observed mitigation measures in 
states, and (2) remove any retrofit assumptions at marginal units that 
would have much higher dollar per ton representative cost and little or 
no air quality benefit. For instance, the EPA does not define the SCR 
retrofit breakpoint ($11,000 per ton) to include retrofit application 
at steam units less than 100 MW or at oil/gas steam units emitting at 
less than 150 tons per ozone season. The emissions reductions from 
these potential categories of measures are small and do not constitute 
additional ``breakpoints'' in EPA's estimation. They would entail much 
higher dollar per ton costs, going beyond what is widely observed in 
the fleet. This careful calibration of technology breakpoints through 
exclusion of measures that are clearly not cost-effective in terms of 
air quality benefit allows for the identification of an EGU strategy 
that is an appropriate reflection of those readily available and widely 
implemented emissions reduction strategies that will have meaningful 
downwind air quality impact.
---------------------------------------------------------------------------

    \191\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
    \192\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
    \193\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    Moreover, these technologies (and representative cost) are 
demonstrated ozone pollution mitigation strategies that are widely 
practiced across the EGU fleet and are of comparable stringency to 
emissions reduction measures that many downwind states have already 
instituted. The coal SCR retrofit measures driving the majority of the 
emissions reductions in this action not only reflect industry best 
practice, but they also reflect prevailing practice among EGUs. More 
than 60% of the existing coal capacity already has this technology in 
place. For nearly 25 years, all new coal-fired EGUs that commenced 
construction have had SCR (or equivalent emissions rates). The 1997 
proposed amendments to subpart Da revised the NOX standard 
based on the use of SCR. The NOX SIP Call (promulgated in 
1998) established emissions reduction requirements premised on 
extensive SCR installation (142 units) and incentivized well over 40 
GWs of SCR retrofit in the ensuing years.\194\ Similarly, the Clean Air 
Interstate Rule established emissions reductions requirements in 2006 
that assumed another 58 units (15 GW) would be installed in the ensuing 
years among just 10 states, and an even greater volume of capacity 
chose SCR retrofit measures in the wake of finalizing that action.\195\
---------------------------------------------------------------------------

    \194\ 63 FR 57448.
    \195\ 71 FR 25345.
---------------------------------------------------------------------------

    Basing emission reduction requirements for EGUs on SCR retrofits is 
also consistent with regulatory approaches adopted by states, which--
particularly in downwind areas more impacted by ozone transport 
contribution from upwind state emissions--have already adopted SCR-
based standards as part of stringent NOX control programs. 
Regulatory programs that impose stringent Reasonably Available Control 
Technology (RACT) requirements on all major power plants and Lowest 
Achievable Emission Rate (LAER) standards on all new major sources of 
NOX have resulted in remaining coal sources in states along 
the Northeast Corridor such as Connecticut, Delaware, New Jersey, New 
York, and Massachusetts all being retrofitted with SCR.\196\ The 
Maryland Code of Regulations requires coal fired sources to operate 
existing SCR controls or install SCR controls by specified dates.\197\ 
Programs like North Carolina's Clean Smokestacks Act and Colorado's 
Clean Air, Clean Jobs Act have also required or prompted SCR retrofits 
on units.\198\ Unit-level Best Available Retrofit Technology (BART) 
requirements for the first Regional Haze planning period also 
determined SCR retrofits (and corresponding emissions rates) were cost-
effective controls for a variety of sources in the U.S.\199\
---------------------------------------------------------------------------

    \196\ EPA-HQ-OAR-2020-0272. Comment letter from Attorneys 
General of NY, NJ, CT, DE, MA.
    \197\ COMAR 26.11.38 (control of NOX Emissions from 
Coal-Fired Electric Generating Units).
    \198\ https://www.epa.gov/system/files/documents/2021-09/table-3-30-state-power-sector-regulations-included-in-epa-platform-v6-summer-2021-refe.pdf.
    \199\ See table 3-35 BART regulations in EPA IPM documentation 
available at https://www.epa.gov/airmarkets/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference-case.
---------------------------------------------------------------------------

    As shown in Figure 1 to Section VI.D.1,\200\ the majority of EGU 
emissions reduction potential and associated air quality improvements 
estimated for 2023 occurs from optimization of existing SCRs, with some 
additional reductions from installation of state-of-the-art combustion 
controls at the same representative cost threshold. At the slightly 
higher representative cost threshold of $1,800 per ton, there is some 
additional air quality improvement from optimization of existing SNCRs. 
These measures taken together represent the control stringency at which 
near-term incremental EGU NOX reduction potential and 
corresponding downwind ozone air quality improvements are maximized. 
This evaluation shows that EGU NOX reductions for each of 
the near-term emissions control technologies are available at 
reasonable cost and that these reductions provide meaningful 
improvements in downwind ozone concentrations at the identified 
nonattainment and maintenance receptors. Figure 1 to Section VI.D.1 
\201\ highlights (1) the continuous connection between identified 
emission reduction potential and downwind air quality improvement 
across the range of near-term mitigation measures assessed, and (2) the 
cost-effective availability of these reductions and corresponding air 
quality improvements.
---------------------------------------------------------------------------

    \200\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
    \201\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    Additional considerations that are unique to EGUs provide 
additional support for EPA's proposal to include SCR and SNCR 
optimization as part of the identified near-term control stringency, 
including:
     These controls are already installed and available for 
operation on these units;
     they are on average already partially operating, but not 
necessarily optimized;
     the reductions are available in the near-term (during 
ozone seasons when the problematic receptors are projected to persist), 
including by the 2023 ozone season aligned with the Moderate area 
attainment date; and
     these sources are already covered under the existing CSAPR 
NOX Ozone Season Group 2 or Group 3 Trading Programs or the 
Acid Rain Program and thus have the monitoring, reporting, 
recordkeeping, and all other necessary elements of compliance with the 
trading program already in place.
    The majority of emissions reduction potential and associated air 
quality improvements estimated for 2026 occur from retrofitting 
uncontrolled steam sources with post-combustion controls. At the 
representative cost threshold of $11,000 per ton, there are significant 
additional air quality improvements from emissions reductions 
commensurate with installation of new SCRs and SNCRs. These measures 
taken together with the near-term emissions reduction measures 
described

[[Page 20095]]

previously represent the level of control stringency in 2026 at which 
incremental EGU NOX reduction potential and corresponding 
downwind ozone air quality improvements are maximized. This evaluation 
shows that EGU NOX reductions for each of the emissions 
control technologies are available at reasonable cost and that these 
reductions can provide improvements in downwind ozone concentrations at 
the identified nonattainment and maintenance receptors.
    The EPA finds that the control stringency that reflects 
optimization of existing SCRs and SNCRs, installation of state-of-the-
art combustion controls, and the retrofitting of new post combustion 
controls at the coal and oil/gas steam capacity described previously 
results in nearly 90,000 tons of NOX reduction 
(approximately 43 percent of the 2026 baseline level) for the 22 linked 
states in 2026 subject to a FIP for EGUs, which will deliver notable 
air quality improvements across all transport-impacted receptors and 
assist in fully resolving one downwind air quality problem for the 2015 
ozone NAAQS. Figure 2 to Section VI.D.1 \202\ demonstrates the 
continuous connection between identified emissions reduction potential 
and downwind air quality improvement across the range of mitigation 
measures assessed in 2026. At no point do the additional emission 
mitigation measures examined here fail to produce corresponding 
downwind air quality improvements.
---------------------------------------------------------------------------

    \202\ Included in Appendix G of the Ozone Transport Policy 
Analysis Proposed Rule TSD, which is available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    The EPA is proposing that emissions reductions commensurate with 
the full operation of all existing post-combustion controls (both SCRs 
and SNCRs) and state-of-the-art combustion control upgrades constitute 
the Agency's selected control stringency for EGUs for those states 
linked to downwind nonattainment or maintenance in 2023. For those 
states also linked in 2026, the EPA is determining that the appropriate 
EGU control stringency also includes emissions reductions commensurate 
with the retrofit of SCR at coal steam units of 100 MW or greater 
capacity (excepting circulating fluidized bed units), new SNCR on coal 
steam units of less than 100 MW capacity and circulating fluidized bed 
units, and SCR on oil/gas steam units greater than 100 MW that have 
historically emitted at least 150 tons of NOX per ozone 
season.
    As noted previously in Section VI.B of this proposed rule and in 
the EGU NOX Mitigation Strategies Proposed Rule TSD, the EPA 
considered other methods of identifying mitigation measures (e.g., SCRs 
on smaller units, combustion control upgrades on combustion turbines, 
SCRs on combustion turbines). The emission reductions from these 
potential categories of measures do not constitute additional 
``technology breakpoints'' in EPA's estimation, but rather reflect a 
different tier of assessment where further mitigation measures are 
based on inclusion of smaller and/or different generator type of unit 
(rather than pollution control technology). Emissions reductions from 
these measures are relatively small and would entail much higher dollar 
per ton costs, going beyond what is widely observed in the fleet. 
Although these additional measures are not included in EPA's technology 
breakpoint analysis discussed above, the EPA did examine the cost, 
potential reductions, and air quality impact of these additional 
measures in a supplemental analysis to affirm that they do not merit 
inclusion in the proposed stringency for this action. Similar to prior 
rules, there is a notable ``knee-in-the-curve'' breakpoint if these 
additional measures are included in EPA's analysis. In other words, 
there are very little additional emissions reductions and air quality 
improvement at problematic receptors, and the cost associated with 
these measures increases substantially on a dollar per ton basis. The 
graphic below illustrates the significant loss in cost-effectiveness of 
reductions if these measures had been included in EPA's proposed 
stringency.\203\
---------------------------------------------------------------------------

    \203\ This is not to discount the potential effectiveness of 
these or other NOX mitigation strategies outside the 
context of this rulemaking to address regional ozone transport on a 
nationwide basis. States and local jurisdictions may find such 
measures particularly impactful or necessary in the context of local 
attainment planning or other unique circumstances. Further, while 
the EPA proposes this rule as a complete remedy to the problem of 
interstate transport for the 2015 ozone NAAQS, the EPA has in the 
past recognized that circumstances may arise after the promulgation 
of remedies under CAA section 110(a)(2)(D)(i)(I) in which the 
exercise of further remedial authority against specific stationary 
sources or groups of sources under CAA section 126 may be warranted. 
See Response to Clean Air Act Section 126(b) Petition From Delaware 
and Maryland, 83 FR 50444, 50453-54 (Oct. 5, 2018).
---------------------------------------------------------------------------

    This proposed determination regarding the appropriate level of 
control stringency for EGUs to eliminate significant contribution from 
upwind states finds that the amounts of NOX emissions 
reduction achieved through these strategies at EGUs are necessary and 
cost-justified under the Step 3 multifactor analysis for as long as the 
strategies remain available to the sources. In other words, the EPA 
finds at Step 3 that so long as the identified NOX emissions 
reduction controls are available and can be implemented (such as 
optimization of SCRs), they must be implemented, even as total 
NOX emissions reductions on a mass basis decline. EPA's Step 
3 finding is not limited to a determination of the mass-based reduction 
in emissions that the EPA determines is achievable for the covered EGU 
fleet under current operating conditions. Rather, the EPA finds at Step 
3 that EGUs must continue to achieve NOX emissions 
performance in the ozone season commensurate with the level of 
emissions control stringency the EPA determines appropriate under the 
multifactor test as set forth in this section. The stringency of the 
emissions budgets would simply reflect the stringency of the emissions 
control strategies and would do so more consistently over time than 
EPA's previous approach of computing emissions budgets for all future 
control periods at the time of the rulemaking. This retention of a 
constant degree of stringency over time in emissions budgets under a 
flexible trading program would not constitute over-control any more 
than the permanent imposition of emissions rate standards on individual 
sources at the time of the rulemaking would constitute over-control.
    EPA acknowledges that this is an adjustment in its historical 
approach to eliminating significant contribution, although it is 
consistent with the evolution of the Agency's thinking as set forth in 
the Revised CSAPR Update. In CSAPR and the CSAPR Update, EPA 
established static budgets at Step 4 based on the selected level of 
control stringency at Step 3. EPA's experience with this approach has 
been that while the initial mass-based budgets are achieved and 
compliance targets are even exceeded, this leads to a loss in efficacy 
of the program as the incentive to reduce emissions declines over time. 
Some sources emit at higher levels or relax their operation of 
NOX controls in response to the build-up of allowances 
available for compliance, even though EPA has concluded those controls 
are necessary to meet the statutory good neighbor requirements. This 
result is inconsistent with the statutory mandate to ``prohibit'' 
significant contribution and interference with maintenance of the NAAQS 
in other states, as evidenced most clearly in CAA section 126, which 
makes it unlawful for a source ``to operate more than three months 
after [a finding that the source emits or would emit in violation of 
the good neighbor provision] has been made with respect

[[Page 20096]]

to it.'' 42 U.S.C. 7426(c)(2) (emphasis added). Moreover, there is no 
policy justification at Step 3 for an upwind source to relax or cease 
operating its emissions controls simply because other sources of 
pollution have been reduced. In the Revised CSAPR Update, the EPA began 
to address this problem by establishing adjusted emissions budgets for 
each year from 2021 through 2025 based on information about the 
changing EGU fleet known at the time of promulgation of the rule. See 
86 FR 23118. As discussed in Section VII.B of this proposed rule, the 
EPA is now implementing a more complete approach to eliminating 
significant contribution by imposing dynamic budget updates and banking 
restrictions to ensure that its selected control stringency at Step 3 
continues to be implemented.
    This approach at Step 4 is wholly consistent with EPA's findings at 
Step 3. This is best illustrated by comparing the trading program 
approach with the requirements the EPA could promulgate for EGUs based 
on an approach of assigning unit-specific emissions rate limitations. 
Under the latter approach, the EPA would assign an enforceable 
emissions rate to each EGU, based on the operation of the selected 
NOX control strategy (e.g., optimizing existing SCRs) that 
would apply in perpetuity. By continually adjusting budgets to ensure 
that emissions outcomes are achieved--and downwind air quality benefits 
are delivered--that are commensurate with the continuous operation of 
emissions controls at the selected control stringency at Step 3, the 
EPA is better aligning the implementation of the program at Step 4 with 
the level of emissions reductions from upwind sources that the EPA has 
determined is appropriate through the Step 3 multifactor analysis.\204\ 
The EPA requests comment on its identified EGU control stringencies, 
including its consideration of the cost, air quality impacts, and 
timing of such mitigation strategies.
---------------------------------------------------------------------------

    \204\ The EPA does not believe this adjustment in its Step 3 
approach for EGUs, or its corresponding, improved approach to the 
trading program at Step 4--which, again, mimics the effect of 
permanent and enforceable unit-specific emissions limits--violates 
the prohibition on over-control. Our over-control analysis is set 
forth below in Section VI.D of this proposed rule, and the EPA 
proposes to find that there is no over-control at the proposed 
stringency (for both EGUs and non-EGUs) in any upwind state.
---------------------------------------------------------------------------

2. Non-EGU Assessment
    The Agency prepared the non-EGU screening assessment for 2026 using 
the analytical framework detailed in Section VI.B.2 of this proposed 
rule. Using a $7,500/ton (in 2016 dollars) marginal cost threshold 
identified in the framework, the screening assessment used CoST with 
known controls, the CMDB, and the 2019 emissions inventory and 
estimated emissions reductions from emissions units in the Tier 1 
industries and impactful boilers in the Tier 2 industries.
    Using 2026 as the potential earliest date by which controls on 
emissions units in the Tier 1 industries and impactful boilers in the 
Tier 2 industries could be installed, the EPA assessed whether these 
emissions reduction controls should be required at Step 3 under its 
multi-factor test.
    The EPA determined that, for 2026, the average air quality 
improvement at receptors relative to the EGU case when SCR post-
combustion controls were installed was 0.18 ppb when Tier 1 non-EGU 
controls were applied and an additional 0.04 ppb when Tier 2 non-EGU 
controls were applied, based on the Step 3 analysis. The EPA determined 
for the purposes of Step 3 that all but 3 receptors remain 
nonattainment or maintenance after the application of these controls, 
with two receptors (one in Brazoria County, Texas and one in Kenosha 
County, Wisconsin) switching from maintenance to attainment with these 
non-EGU controls in place.

                                        Table VI.D.2-2--Air Quality at Receptors in 2026 From Non-EGU Industries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Average DV  (ppb)                        Max DV  (ppb)
                                                                            ----------------------------------------------------------------------------
                                                                                                EGU SCR/SNCR
                                                                                               optimization +                          EGU SCR/SNCR
          Monitor ID No.                  State                County            Baseline      LNB  upgrade +       Baseline        optimization + LNB
                                                                               (engineering       SCR/SNCR        (engineering      upgrade + SCR/SNCR
                                                                                analysis)      retrofit + non-     analysis)        retrofit + non-EGU
                                                                                                EGU  Tier 1 +                        Tier 1 + Tier 2
                                                                                                   Tier 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
40278011.........................  Arizona............  Yuma...............            70.11            70.06             71.81                    71.76
80350004.........................  Colorado...........  Douglas............            70.94            70.07             71.55                    70.67
80590006.........................  Colorado...........  Jefferson..........            72.09            71.26             72.69                    71.86
80590011.........................  Colorado...........  Jefferson..........            72.97            72.16             73.68                    72.86
90010017.........................  Connecticut........  Fairfield..........            71.60            71.35             72.30                    72.04
90013007.........................  Connecticut........  Fairfield..........            73.09            72.54             73.99                    73.43
90019003.........................  Connecticut........  Fairfield..........            74.83            74.40             75.03                    74.59
90099002.........................  Connecticut........  New Haven..........            70.77            70.22             72.78                    72.21
170310001........................  Illinois...........  Cook...............            69.05            68.73             72.87                    72.53
170310032........................  Illinois...........  Cook...............            69.37            69.20             71.98                    71.80
170310076........................  Illinois...........  Cook...............            68.75            68.51             71.56                    71.31
170314201........................  Illinois...........  Cook...............            69.10            68.83             72.61                    72.32
170317002........................  Illinois...........  Cook...............            69.36            68.98             72.27                    71.88
480391004........................  Texas..............  Brazoria...........            70.93            68.72             73.09                    70.81
482010024........................  Texas..............  Harris.............            76.28            74.23             77.82                    75.73
490110004........................  Utah...............  Davis..............            72.20            71.51             74.42                    73.70
490353006........................  Utah...............  Salt Lake..........            73.00            72.30             74.61                    73.90
490353013........................  Utah...............  Salt Lake..........            74.10            73.34             74.60                    73.84
490570002........................  Utah...............  Weber..............            70.30            69.63             72.22                    71.53
550590019........................  Wisconsin..........  Kenosha............            72.01            71.57             72.91                    72.47
550590025........................  Wisconsin..........  Kenosha............            68.46            67.95             71.48                    70.95
551010020........................  Wisconsin..........  Racine.............            70.52            70.12             72.42                    72.02
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average AQ Change Relative to Base (ppb).......................................................................................                     0.64
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 20097]]

 
Total PPB Change Across All Receptors Relative to Base (ppb)...................................................................                    14.13
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For more information about how this assessment was performed and 
the results of the analysis for each receptor, refer to the Ozone 
Transport Policy Analysis Proposed Rule TSD and to the Ozone AQAT 
included in the docket for this rule.
a. Request for Comment on Non-EGU Control Strategies and Measures
    In the non-EGU screening assessment, the EPA used CoST, the CMDB, 
and the 2019 emissions inventory to assess emissions reduction 
potential from non-EGU emissions units in several industries. The EPA 
identified emissions units that were uncontrolled or that could be 
better controlled and then applied control technologies to estimate 
emissions reductions and costs. As noted previously, the cost estimates 
do not include monitoring, recordkeeping, reporting, or testing costs. 
Based on the available information, the EPA is proposing to require 
implementation of the non-EGU emissions reductions at Step 3 by the 
beginning of the 2026 ozone season. The EPA discusses the basis for 
this proposed compliance schedule in Section VII.A.2 of this proposed 
rule.
    The EPA requests comment on certain estimates and assumptions in 
this proposal that may affect EPA's evaluation of the capital and 
annual costs of several potential control technologies. In particular, 
the EPA requests comment on whether ultra-low NOX burners or 
low NOX burners are generally considered part of the process 
or add-on controls for ICI boilers (and how process changes or 
retrofits to accommodate controls would affect the cost estimates). We 
request comment on our estimates regarding the effectiveness of low 
emissions combustion in controlling NOX from RICE compared 
to other potential NOX controls for these engines. We 
request comment on whether controls on ICI boilers and reciprocating IC 
engines are likely to be run all year (e.g., 8,760 hours/year) or only 
during the ozone season.
    The EPA notes that the non-EGU NOX mitigation strategy 
in this proposed rule focuses on obtaining emissions reductions from 
non-EGU units that were quantitatively determined to have the most 
significant impacts on air quality improvements at the downwind 
nonattainment and maintenance receptors. However, the EPA requests 
comment on the merits of requiring non-EGU sources within the linked 
upwind states to meet specified technology-based control standards, 
such as the RACT SIP requirements outlined in CFR part 51 for non-EGU 
sources located in OTR states.
3. Combined EGU and Non-EGU Assessment
    The EPA used the Ozone AQAT to evaluate the combined impact of 
these selected stringency levels for both EGUs and non-EGUs on all 
receptors remaining in the 2026 air quality modeling base case to 
inform the over-control analysis. EPA's evaluation demonstrated air 
quality improvement at the 22 remaining nonattainment or maintenance 
receptors outside of California (see Section V.D of this proposed rule 
for receptor details). The EPA estimated that the average air quality 
improvement at these receptors relative to the engineering analytics 
base case was 0.64 ppb for emissions reductions commensurate with 
optimization of existing SCRs/SNCRs, combustion control upgrades, 
application of new post-combustion control (SCR and SNCR) retrofits at 
eligible units, and all estimated emissions reductions from the Tier 1 
industries and impactful boilers in the Tier 2 industries. Table 
VI.D.1-3 summarizes the results of EPA's Step 3 evaluation of air 
quality improvements at these receptors using AQAT. In summary, the 
collective application of these mitigation measures and emissions 
reductions continue to deliver downwind air quality improvements up 
until the most stringent thresholds identified. The health and climate 
benefits resulting from application of these measures (as described in 
the RIA) are estimated to exceed the costs, and the identified 
technologies reflect not only demonstrated best practices--but widely 
adopted best practices in the case of EGU retrofits.

  Table VI.D.3-1--Change in Air Quality Reductions at Receptors in 2026 From Proposed EGU and Non-EGU Emissions
                                             Reductions \a\ \b\ \c\
----------------------------------------------------------------------------------------------------------------
                                                                                   Total PPB       Average PPB
                                                                 Ozone season    change across    change across
                       Tier/technology                            emissions       all downwind     all downwind
                                                                  reductions     receptors \d\      receptors
----------------------------------------------------------------------------------------------------------------
EGU (SCR/SNCR optimization + LNB upgrade) + Gen shifting.....           26,250             1.53             0.07
EGU SCR/SNCR Retrofit + Gen shifting.........................           63,883             7.89             0.36
Non-EGU (Tier 1).............................................           41,153             3.89             0.18
Non-EGU (Tier 2).............................................            6,033             0.82             0.04
                                                              --------------------------------------------------
    Total....................................................  ...............            14.13             0.64
----------------------------------------------------------------------------------------------------------------
Table Notes:

[[Page 20098]]

 
\a\ As in prior rules, for the purpose of defining significant contribution at Step 3, the EPA evaluated air
  quality changes resulting from the application of the emissions reductions in only those states that are
  linked to each receptor as well as the state containing the receptor. By applying reductions to the state
  containing the receptor, the EPA ensures that it is accounting for the downwind state's fair share. In
  addition, this method holds each upwind state responsible for its fair share of the downwind problems to which
  it is linked. Reductions made by other states in order to address air quality problems at other receptors do
  not increase or decrease this share. The air quality impacts on design values that reflect the emissions
  reductions in all linked states and the health and climate benefits from this proposal are discussed in
  Section IX of this proposed rule.
\b\ The EPA notes that the design values reflected in Tables VI.D.1-1 and 2 correspond to the engineering
  analysis EGU emissions inventory used in AQAT to determine state-level baseline emissions and reductions at
  Step 3. These tools are discussed in greater detail in the Ozone Transport Policy Analysis Proposed Rule TSD.
  Additionally, these emission reduction values vary slightly from the technology reduction estimates described
  in Section VI.C, as the values here reflect (1) the sum of the final identified stringency for each state
  (e.g., SCR retrofit potential is not assumed in Alabama, Delaware, and Tennessee), and (2) generation shifting
  reduction potential identified at each step.
\c\ The total and average ppb results from non-EGUs emissions reductions shown here were generated using the
  Step 3 AQAT methodology consistent with that for EGUs (i.e., including reductions from the state containing
  the receptor and excluding states that are not explicitly linked to particular receptors). The values shown in
  Table VI.C.2-1 were prepared for the non-EGU screening assessment using a methodology where states within the
  program make emissions reductions for all receptors. States that contain receptors (i.e., Connecticut and
  Colorado) that are not linked to other receptors are not assumed to make reductions under that methodology.
\d\ The cumulative ppb change only shows the aggregate change across all problematic receptors (some of which
  are located within close proximity to one another) in this part of the Step 3 analysis. Section IX of this
  proposed rule provides a more complete picture of the air quality impacts of the proposed rule.

4. Over-Control Analysis
    The EPA applied its over-control test to this same set of 
aggregated EGU and non-EGU data described in the previous section. As 
part of the air quality analysis using the Ozone AQAT, the EPA 
evaluated potential over-control with respect to whether (1) the 
expected ozone improvements would be greater than necessary to resolve 
the downwind ozone pollution problem (i.e., beyond what is necessary to 
resolve all nonattainment and maintenance problems to which an upwind 
state is linked) or (2) the expected ozone improvements would reduce 
the upwind state's ozone contributions below the screening threshold 
(i.e., 1 percent of the 2015 ozone NAAQS).
    In EME Homer City, the Supreme Court held that the EPA cannot 
``require[ ] an upwind State to reduce emissions by more than the 
amount necessary to achieve attainment in every downwind State to which 
it is linked.'' 572 U.S. at 521. On remand from the Supreme Court, the 
D.C. Circuit held that this means that the EPA might overstep its 
authority ``when those downwind locations would achieve attainment even 
if less stringent emissions limits were imposed on the upwind States 
linked to those locations.'' EME Homer City II, 795 F.3d at 127. The 
D.C. Circuit qualified this statement by noting that this ``does not 
mean that every such upwind state would then be entitled to less 
stringent emissions limits. Some of those upwind States may still be 
subject to the more stringent emissions limits so as not to cause other 
downwind locations to which those States are linked to fall into 
nonattainment.'' Id. at 14-15. As the Supreme Court explained, ``while 
EPA has a statutory duty to avoid over-control, the Agency also has a 
statutory obligation to avoid `under-control,' i.e., to maximize 
achievement of attainment downwind.'' 572 U.S. at 523. The Court noted 
that ``a degree of imprecision is inevitable in tackling the problem of 
interstate air pollution'' and that incidental over-control may be 
unavoidable. Id. ``Required to balance the possibilities of under-
control and over-control, EPA must have leeway in fulfilling its 
statutory mandate.'' Id.\205\
---------------------------------------------------------------------------

    \205\ Although the Court described over-control as going beyond 
what is needed to address ``nonattainment'' problems, the EPA 
interprets this holding as not impacting its approach to defining 
and addressing both nonattainment and maintenance receptors. In 
particular, the EPA continues to interpret the Good Neighbor 
provision as requiring it to give independent effect to the 
``interfere with maintenance'' prong. Accord Wisconsin, 938 F.3d at 
325-27.
---------------------------------------------------------------------------

    Consistent with these instructions from the Supreme Court and the 
D.C. Circuit, using the Ozone AQAT, the EPA first evaluated whether 
reductions resulting from the selected control stringencies for EGUs in 
2023 and 2026 combined with the emissions reductions selected for non-
EGUs in 2026 can be anticipated to resolve any downwind nonattainment 
or maintenance problems (see the Ozone Policy Analysis Proposed Rule 
TSD for details on the construction and application of AQAT). The 
control stringency selected for 2023 (a representative cost threshold 
of $1,800 per ton for EGUs) includes emissions reductions commensurate 
with optimization of existing SCRs and SNCRs and installation of state-
of-the-art combustion controls, which are estimated to change the 
status of one maintenance receptor, shifting the Clark County, Nevada 
monitor to attainment in 2023. However, no other nonattainment or 
maintenance problems would be resolved in 2023 with this level of 
stringency, and no state is linked solely to this receptor. Nor do any 
states' contribution levels drop below the 1% of NAAQS threshold. Thus, 
the EPA determined that none of the 26 linked states have all of their 
linkages resolved at the proposed EGU level of control stringency in 
2023, and hence, the EPA finds no over-control in the proposed level of 
stringency.
    Based on the air quality baseline modeling for 2026, all receptors 
to which Alabama, Delaware, and Tennessee are linked in 2023 are 
projected to be in attainment in 2026. Therefore, no additional 
emissions reductions are proposed for EGUs or non-EGUs in those states 
beyond the 2023 level of stringency. For the remaining 23 states, the 
selected control stringency (at a representative cost per ton threshold 
of $11,000 for EGUs and a marginal cost threshold of $7,500 for non-
EGUs) beginning in 2026 includes additional EGU controls and estimated 
non-EGU emissions reductions for Tier 1 and Tier 2 non-EGU industries. 
The EPA used the Ozone AQAT to evaluate the impact of this selected 
stringency level (as well as other potential stringency levels) on all 
receptors remaining in the 2026 air quality modeling base case. This 
assessment shows that the selected control stringency level and 
emissions reductions are estimated to change the status of three 
maintenance receptors to attainment in 2026--Douglas County, Colorado; 
Brazoria County, Texas; and Kenosha County, Wisconsin. Based on these 
data, EPA proposes that at least 20 of the 23 states continue to be 
linked to nonattainment or maintenance receptors after implementation 
of all identified Step 3 reductions, and hence, the EPA finds no over-
control in its determination of that level of stringency for those 20 
states.
    For 2 of the 23 states, Arkansas and Mississippi, the last downwind 
receptor to which these two states are linked (i.e., Brazoria County, 
Texas) is estimated to achieve attainment and maintenance after full 
application of EGU reductions and Tier 1 non-EGU reductions. This 
suggests application of the estimated non-EGU emissions reductions from 
Tier 2 may constitute over-control for these states. However, this 
downwind

[[Page 20099]]

receptor only resolves by a small margin after the application of all 
EGU and Tier 1 non-EGU emissions reductions. The EPA anticipates that 
updates to emissions inventories, emissions reduction potential from 
identified technologies, or the over-control test methodology resulting 
from comments or other updated information could possibly move this 
site back into nonattainment- or maintenance-receptor status when the 
EPA conducts an over-control analysis prior to finalizing this 
proposal.
    For 1 of the 23 states, Wyoming, the EPA also notes a potential 
over-control finding under the methodological assumption where 
emissions reductions of commensurate stringency are assumed in the 
downwind state of Colorado (which is not subject to this proposal). As 
demonstrated in the Ozone Transport Policy Analysis Proposed Rule TSD, 
the last downwind receptor for Wyoming (i.e., Douglas County, Colorado) 
is estimated to achieve attainment and maintenance after full 
application of EGU reductions. This suggests application of estimated 
non-EGU emissions reductions from Tier 1 and Tier 2 industries may 
constitute over-control for this state. However, when the assumption of 
commensurate downwind state reductions in Colorado is removed from the 
methodology, the downwind receptor to which Wyoming is linked does not 
resolve and there is no identified over-control estimated for 
Wyoming.\206\
---------------------------------------------------------------------------

    \206\ In this proposal, the EPA continues to assume, as it has 
in prior transport rules, that home-states (that are not otherwise 
linked) will make similar reductions as those assumed in this action 
for purposes of local attainment. While the EPA continues to view 
this to be an equitable means of assessing air quality improvement 
from good neighbor actions, because the downwind receptor state is 
assumed to do its ``fair share,'' the EPA recognizes that recent 
case law has called the need for such an assumption into question, 
and thus using this assumption as a basis for finding over-control 
may be inappropriate. In Maryland, the EPA had argued that good 
neighbor obligations should not be required by the Marginal area 
attainment deadline in part because ``marginal nonattainment areas 
often achieve the NAAQS without further downwind reductions, so it 
would be unreasonable to impose reductions on upwind sources based 
on the next marginal attainment deadline.'' 958 F.3d 1185, 1204. The 
D.C. Circuit rejected that argument, noting regulatory consequences 
for the downwind state for failure to attain even at the Marginal 
date, and, citing Wisconsin, the court held that upwind sources 
violate the good neighbor provision if they significantly contribute 
even at the Marginal area attainment date. Id. Thus, the EPA 
examines over-control in this proposal with and without this 
assumption of home-state emission reductions.
---------------------------------------------------------------------------

    Next, the EPA evaluated the potential for over-control with respect 
to the 1 percent of the NAAQS threshold applied in this proposed 
rulemaking at Step 3 of the good neighbor framework, assessed for the 
selected control stringencies for each state for each period that 
downwind nonattainment and maintenance problems persist (i.e., 2023 and 
2026). Specifically, the EPA evaluated whether the selected control 
stringencies would reduce upwind emissions to a level where the 
contribution from any of the 26 linked states in 2023 or 23 linked 
states in 2026 would be below the 1 percent threshold. The EPA finds 
that for the mitigation measures assumed in 2023 and in 2026, all 
states that contributed greater than or equal to the 1 percent 
threshold in the base case continued to contribute greater than or 
equal to 1 percent of the NAAQS to at least one remaining downwind 
nonattainment or maintenance receptor for as long as that receptor 
remained in nonattainment or maintenance. In the case of Arkansas, 
Mississippi, and Wyoming, while their linkages resolved based on a 
change in receptor status at Step 1 (as discussed above), their 
contribution to the relevant monitoring sites remained above 1 percent 
of the NAAQS, and thus, the potential basis for an over-control finding 
with respect to these states is not based on their contribution 
dropping below 1 percent of the NAAQS at those sites. For more 
information about this assessment, refer to the Ozone Transport Policy 
Analysis Proposed Rule TSD and the Ozone AQAT.
    Based on these results, under no scenario does EPA's AQAT analysis 
for this proposal indicate that including all identified EGU reductions 
would constitute over-control. Rather, if these results hold for a 
final rule, the potential over-control for Arkansas and Mississippi can 
be avoided by not requiring Tier 2 non-EGU reductions, and over-control 
for Wyoming can be avoided by not requiring any non-EGU reductions.
    Nonetheless, while acknowledging these preliminary analytic 
results, the EPA is proposing that all of the selected EGU and non-EGU 
NOX reduction strategies selected in EPA's Step 3 analysis 
be applied to all linked states in 2026--including to Arkansas, 
Mississippi, and Wyoming--to eliminate significant contribution to 
nonattainment and interference with maintenance of the 2015 ozone 
NAAQS. The Supreme Court has directed the EPA to avoid both over-
control and under-control in addressing good neighbor obligations. In 
addition, the D.C. Circuit has reinforced that over-control must be 
established based on particularized, record evidence on an as-applied 
basis. As noted previously, even slight changes in analytics based on 
comments or new information between proposal and final could result in 
the Brazoria, Texas site remaining either a nonattainment or 
maintenance receptor. Further, with respect to Wyoming, its linkage 
only resolves based on an unenforceable assumption regarding a certain 
level of emissions reduction in Colorado. The proposed determination 
that the stringency of this proposal does not constitute over-control 
for any linked state is further reinforced by EPA's observation in 
Section IV.A.1 of this proposed rule regarding the nature of ozone, and 
in particular, that future ozone concentrations and the formation of 
ground level ozone, may be impacted by climate change in future years.
    Under these circumstances, the EPA cannot conclude based on the 
current record that any aspect of its selected Step 3 level of control 
stringency constitutes unnecessary over-control for any of the 23 
states found to be linked in 2026. The EPA requests comment on this 
proposed conclusion. The EPA requests comment on an alternative 
conclusion that, if this same analysis were to persist for a final 
rule, it must limit non-EGU reduction requirements for Arkansas and 
Mississippi to only the Tier 1 industries, and for Wyoming to limit the 
stringency of the rule to only the EGU reduction strategies.

VII. Implementation of Emissions Reductions

A. NOX Reduction Implementation Schedule

    This proposal, if finalized, will ensure that emissions reductions 
necessary to eliminate significant contribution will be achieved as 
``as expeditiously as practicable'' as required under CAA section 
181(a). The EPA's anticipated timing will provide for all possible 
emissions reductions to go into effect beginning in the 2023 ozone 
season, which is aligned with the next upcoming attainment date of 
August 3, 2024, for areas classified as Moderate nonattainment under 
the 2015 ozone standard. Additional emissions reductions that the EPA 
finds not possible to implement by that attainment date are proposed to 
take effect as expeditiously as practicable, with the full suite of 
emissions reductions taking effect by the 2026 ozone season, which is 
aligned with the August 3, 2027, attainment date for areas classified 
as Serious nonattainment under the 2015 ozone NAAQS. This schedule of 
emissions reductions meets the requirement in the Good Neighbor 
Provision that it must be

[[Page 20100]]

implemented ``consistent with the provisions of [title I of the CAA.]'' 
CAA section 110(a)(2)(D)(i). Finally, the timing of this proposed 
rulemaking is designed to achieve reductions as expeditiously as 
practicable while adhering to the procedural requirements of CAA 
section 110. The EPA proposes this rule to constitute a full remedy for 
interstate transport for the 2015 ozone NAAQS for the states covered by 
this proposal; the EPA does not anticipate further rulemaking to 
address good neighbor obligations will be required for these states 
with the finalization of this rule.
    EPA's proposed determinations regarding the timing of this proposed 
rule are informed by and in compliance with several recent court 
decisions. The D.C. Circuit has reiterated several times since 2008 
that, under the terms of the Good Neighbor Provision, upwind states 
must eliminate their significant contributions to downwind areas 
``consistent with the provisions of [title I of the Act],'' including 
those provisions setting attainment deadlines for downwind areas.\207\ 
In North Carolina, the D.C. Circuit found the 2015 compliance deadline 
that the EPA had established in CAIR unlawful in light of the downwind 
nonattainment areas' 2010 deadline for attaining the 1997 NAAQS for 
ozone and PM2.5.\208\ Similarly, in Wisconsin, the Court 
found the CSAPR Update unlawful to the extent it allowed upwind states 
to continue their significant contributions to downwind air quality 
problems beyond the downwind states' statutory deadlines for attaining 
the 2008 ozone NAAQS.\209\ More recently, in Maryland, the Court found 
the EPA's selection of a 2023 analysis year in evaluating state 
petitions submitted under CAA section 126 unlawful in light of the 
downwind Marginal nonattainment areas' 2021 deadline for attaining the 
2015 ozone NAAQS.\210\ The Court noted in Wisconsin that the statutory 
command--that compliance with the Good Neighbor Provision must be 
achieved in a manner ``consistent with'' title I of the CAA--may be 
read to allow for some deviation from the mandate to eliminate 
prohibited transport by downwind attainment deadlines, ``under 
particular circumstances and upon a sufficient showing of necessity,'' 
but concluded that ``[a]ny such deviation would need to be rooted in 
Title I's framework'' and would need to ``provide a sufficient level of 
protection to downwind States.'' \211\
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    \207\ North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), 
Wisconsin v. EPA, 938 F.3d 303 (D.C. Cir. 2019), and Maryland v. 
EPA, 958 F.3d 1185 (D.C. Cir. 2020).
    \208\ North Carolina, 531 F.3d at 911-913.
    \209\ Wisconsin, 938 F. 3d at 303, 3018-20.
    \210\ Maryland, 958 F.3d at 1203-1204. Similarly, in New York v. 
EPA, 964 F.3d 1214 (D.C. Cir. 2020), the Court found the EPA's 
selection of a 2023 analysis year in evaluating New York's section 
126 petition unlawful in light of the New York Metropolitan Area's 
2021 Serious area deadline for attaining the 2008 ozone NAAQS. 964 
F.3d at 1226 (citing Wisconsin and Maryland).
    \211\ Wisconsin, 938 F. 3d at 320 (citing CAA section 181(a) 
(allowing one-year extension of attainment deadlines in particular 
circumstances) and North Carolina, 531 F.3d at 912).
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1. 2023-2025: EGU NOX Reductions Beginning in 2023
    The near-term EGU control stringencies and corresponding reductions 
in this proposed rulemaking cover the 2023, 2024, and 2025 ozone 
seasons. This is the period in which some reductions will be available, 
but the large portion of full remedy reductions--mainly those 
reductions that are driven by post combustion control installation--
identified in Sections VI.B through VI.D of this proposed rule are not 
yet available. The EGU NOX mitigation strategies available 
during these initial 3 years are the optimization of existing post-
combustion controls (SCRs and SNCRs) and combustion control upgrades. 
As described in Sections VI.B through VI.D of this proposed rule and in 
accompanying TSDs, these mitigation measures can be implemented in 
under two months in the case of existing control optimization and in 6 
months in the case of combustion control upgrades.
    As described in Section VI.B of this proposed rule and in the 
identified TSDs, these timing assumptions account for planning, 
procurement, and any physical or structural modification necessary. The 
EPA provides significant historical data, including the implementation 
of the most recent Revised CSAPR Update, as well as engineering studies 
and input factor analysis documenting the feasibility of these timing 
assumptions. However, these timing assumptions are representative of 
fleet averages, and the EPA has noted that some units will likely 
overperform their installation timing assumptions, while others may 
have unit configuration or operational considerations that result in 
their underperforming these timing assumptions. As in prior interstate 
transport rules, the EPA is implementing these EGU reductions through a 
trading program approach. The trading program's option to buy 
additional allowances provides flexibility in the program for outlier 
sources that may need more time than what is representative of the 
fleet average to implement these mitigation strategies while providing 
an economic incentive to outperform rate and timing assumptions for 
those sources that can do so. In effect, this trading program 
implementation operationalizes the mitigation measures as state-wide 
assumptions for the EGU fleet rather than unit-specific assumptions.
    However, starting in 2024, as described in Section VII.B.7 of this 
proposed rule, unit-specific daily emissions rate limits are applied to 
coal units with existing SCR at a level consistent with operating that 
control. The EPA believes that implementing these emissions reductions 
at the state level starting in 2023 (through state emissions budgets) 
while imposing the unit-specific emissions rate limits in 2024 achieves 
the necessary environmental performance as soon as possible while 
accommodating any heterogeneity in unit-level implementation schedules 
regarding daily operation of optimized SCRs.
    Additionally, as in prior rules, the EPA assumes combustion control 
upgrade implementation may take up to 6 months. In the Revised CSAPR 
Update, covering 12 of the 25 states for which emissions reduction 
requirements for EGUs are established under this proposed action, the 
EPA finalized the rule in March of 2021 and thus did not require these 
combustion control-based emissions reductions in ozone-season state 
emissions budgets until 2022 (year two of that program).\212\ The EPA 
is applying the same timing assumption regarding combustion control 
upgrades for this proposed rulemaking given the expected similar window 
between an anticipated final action date and the start of the year one 
ozone season. The EPA is not assuming the implementation of any 
additional combustion control upgrades in state emissions budgets until 
2024. Therefore, those 13 states covered in this action for EGU 
emissions reductions that were not covered in the Revised CSAPR Rule 
have 2023 emissions budgets that only reflect optimization of existing 
controls. Any identified combustion control upgrade emissions 
reductions are reflected beginning in the 2024 ozone-season budgets for 
these states. For the 12 states covered under the Revised CSAPR Update, 
any identified emissions reduction potential from combustion control 
upgrade was included and reflected in those state budgets beginning in 
2022 under the Revised CSAPR Update. Therefore, the

[[Page 20101]]

EPA is assuming that this combustion control upgrade potential is 
available, if not already realized, by the first year of this action 
(i.e., 2023) in this proposed rule.
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    \212\ 86 FR 23093.
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2. 2026 and Later Years: EGU and Non-EGU NOX Reductions 
Beginning in 2026
    In accordance with the good neighbor provision and the downwind 
attainment schedule under CAA section 181 for the 2015 ozone NAAQS, the 
EPA is proposing to align its analysis and implementation of the 
emissions reductions addressing significant contribution from EGU and 
non-EGU sources that require relatively longer lead time at a sectoral 
scale with the 2026 ozone season, which is the last full ozone season 
preceding the August 3, 2027, Serious area attainment date for the 2015 
ozone NAAQS.\213\ The EPA proposes to find that this compliance 
deadline is the most expeditious date practicable and would achieve the 
required emissions reductions prior to the next applicable attainment 
date by which such reductions are, in fact, possible. The EPA proposes 
to find that it is not possible to require implementation of all 
necessary emissions controls across all of the affected EGU and non-EGU 
sources by the August 3, 2024, Moderate area attainment date.
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    \213\ For each nonattainment area classified under CAA section 
181(a) for the 2015 ozone NAAQS, the attainment date is ``as 
expeditiously as practicable'' but not later than the date provided 
in table 1 to 40 CFR 51.1303(a). Thus, for areas initially 
designated nonattainment effective August 3, 2018 (83 FR 25776), the 
latest permissible attainment dates are: August 3, 2021 (for 
Marginal areas), August 3, 2024 (for Moderate areas), August 3, 2027 
(for Serious areas), and August 3, 2033 (for Severe areas).
---------------------------------------------------------------------------

    Thus, the EPA is proposing to require compliance with the control 
requirements for all non-EGUs and the EGU reductions related to post-
combustion control retrofit identified in this section no later than 
the 2026 ozone season (May through September). If finalized in early 
2023, the final rule would provide more than three years for EGU and 
non-EGU sources to install whatever controls they deem suitable to 
comply with required emissions reductions by the 2026 ozone season. In 
addition, the publication of this proposal provides roughly an 
additional year of notice to these source owners and operators that 
they should begin engineering and financial planning now to be prepared 
to meet this implementation timetable.
    The EPA views this timeframe for retrofitting post-combustion 
NOX emissions controls and other non-EGU controls to be 
presumptively reasonable and achievable. A 3-year period for 
installation of post-combustion control technologies is consistent with 
the statutory timeframe for implementation of the controls required to 
address interstate pollution under section 110(a)(2)(D) and 126 of the 
Act, the statutory timeframes for implementation of RACT in ozone 
nonattainment areas classified as Moderate or above, and other 
statutory provisions that establish control requirements for existing 
stationary sources of pollution.
    For example, section 126 of the CAA authorizes a downwind state or 
tribe to petition the EPA for a finding that emissions from ``any major 
source or group of stationary sources'' in an upwind state contribute 
significantly to nonattainment in, or interfere with maintenance by, 
the downwind state. If the EPA makes a finding that a major source or a 
group of stationary sources emits or would emit pollutants in violation 
of the relevant prohibition in CAA section 110(a)(2)(D), the source(s) 
must shut down within 3 months from the finding unless the EPA directly 
regulates the source(s) by establishing emissions limitations and a 
compliance schedule extending no later than three years from the date 
of the finding, to eliminate the prohibited interstate transport of 
pollutants as expeditiously as practicable.\214\ Thus, in the provision 
that allows for direct federal regulation of sources violating the good 
neighbor provision, Congress established 3 years as the maximum amount 
of time available from a final action to when emissions reductions need 
to be achieved at the relevant source or group of sources.
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    \214\ CAA 110(a)(2)(D)(i) and 126(c).
---------------------------------------------------------------------------

    Additionally, for ozone nonattainment areas classified as Moderate 
or higher, the CAA requires states to implement RACT requirements less 
than three years after the statutory deadline for submitting these 
measures to the EPA.\215\ Specifically, for these areas, CAA sections 
182(b)(2) and 182(f) require that states implement RACT for existing 
VOC and NOX sources as expeditiously as practicable but no 
later than May 31, 1995, approximately 30 months after the November 15, 
1992, deadline for submitting RACT SIP revisions. For purposes of the 
2015 ozone NAAQS, the EPA has interpreted these provisions to require 
implementation of RACT SIP revisions as expeditiously as practicable 
but no later than January 1 of the fifth year after the effective date 
of designation, which is less than 3 years after the deadline for 
submitting RACT SIP revisions.\216\ For areas initially designated 
nonattainment with a Moderate or higher classification effective August 
3, 2018 (83 FR 25776), that implementation deadline falls on January 1, 
2023, approximately 29 months after the August 3, 2020 submission 
deadline.\217\ Moderate ozone nonattainment areas must also implement 
all reasonably available control measures (including RACT) needed for 
expeditious attainment within three years after the statutory deadline 
for states to submit these measures to the EPA as part of a Moderate 
area attainment demonstration.\218\
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    \215\ See, e.g., 40 CFR 51.1112(a)(3) and 51.1312(a)(3)(i) 
(requiring implementation of RACT required pursuant to initial 
nonattainment area designations no later than January 1 of the fifth 
year after the effective date of designation, which is less than 3 
years after the submission deadline under 40 CFR 51.1112(a)(2)) and 
51.1312(a)(2)(i), respectively).
    \216\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP 
revisions no later than 24 months after the effective date of 
designation) and 51.1312(a)(3)(i) (requiring implementation of RACT 
SIP revisions as expeditiously as practicable, but no later than 
January 1 of the fifth year after the effective date of 
designation). For reclassified areas, states must implement RACT SIP 
revisions as expeditiously as practicable, but no later than the 
start of the attainment year ozone season associated with the area's 
new attainment deadline, or January 1 of the third year after the 
associated SIP revision submittal deadline, whichever is earlier; or 
the deadline established by the Administrator in the final action 
issuing the area reclassification. 40 CFR 51.1312(a)(3)(ii); see 
also 83 FR 62989, 63012-63014.
    \217\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP 
revisions no later than 24 months after the effective date of 
designation).
    \218\ See, e.g., 40 CFR 51.1108(d) (requiring implementation of 
all control measures (including RACT) needed for expeditious 
attainment no later than the beginning of the attainment year ozone 
season, which, for a Moderate nonattainment area, occurs less than 3 
years after the deadline for submission of reasonably available 
control measures under 40 CFR 51.1112(c) and 51.1108(a)) and 40 CFR 
51.1308(d) (requiring implementation of all control measures 
(including RACT) needed for expeditious attainment no later than the 
beginning of the attainment year ozone season, which, for a Moderate 
nonattainment area, occurs less than three years after the deadline 
for submission of reasonably available control measures under 40 CFR 
51.1312(c) and 51.1308(a)). Because the attainment demonstration for 
a Moderate nonattainment area (including RACT needed for expeditious 
attainment) is due three years after the effective date of the 
area's designation (40 CFR 51.1308(a) and 51.1312(c)), and all 
Moderate nonattainment areas must attain the NAAQS as expeditiously 
as practicable but no later than 6 years after the effective date of 
the area's designation (40 CFR 51.1303(a)), the beginning of the 
``attainment year ozone season'' (as defined in 40 CFR 51.1300(g)) 
for such an area is less than three years after the due date for the 
attainment demonstration.
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    The EPA notes that the types and sizes of the EGU and non-EGU 
sources that the EPA proposes to include in this proposed rule, as well 
as the types of emissions control technologies on which the EPA 
proposes to base the

[[Page 20102]]

emissions limitations that would take effect for the 2026 ozone season, 
generally are intended to be consistent with the scope and stringency 
of RACT requirements for existing major sources of NOX in 
downwind Moderate nonattainment areas and some upwind areas, which many 
states have already implemented in their SIPs.\219\ Thus, the timing 
Congress allotted for sources in downwind states to come into 
compliance with RACT requirements bears directly on the amount of time 
that should be allotted here and indicates, as does CAA section 126, 
that 3 years is an outer limit on the time that should be given sources 
to come into compliance.
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    \219\ See the Non-EGU Sectors TSD for a discussion of SIP-
approved RACT rules in effect in downwind states.
---------------------------------------------------------------------------

    Finally, with respect to emissions standards for hazardous air 
pollutants, section 112(i)(3) of the CAA requires the EPA to establish 
compliance dates for each category or subcategory of existing sources 
subject to an emissions standard that ``provide for compliance as 
expeditiously as practicable, but in no event later than 3 years after 
the effective date of such standard,'' with limited exceptions.\220\ 
Here again, where Congress was concerned with addressing emissions of 
pollutants that impact public health, a 3-year time period was allotted 
as the time needed for existing sources to come into compliance.
---------------------------------------------------------------------------

    \220\ CAA section 112(i)(3)(B) generally authorizes the EPA to 
grant an extension of up to 1 additional year for an existing source 
to comply with emissions standards ``if such additional period is 
necessary for the installation of controls,'' and sections 112(i)(4) 
through (8) provide for limited extensions granted by the President 
where certain conditions are met, for existing sources that have 
installed the best available control technology (BACT) or technology 
required to meet a lowest achievable emissions rate (LAER), and for 
new sources for which construction or reconstruction is commenced by 
certain dates.
---------------------------------------------------------------------------

    All of these statutory timeframes for implementation of new control 
requirements on existing stationary sources indicate that Congress 
considered 3 years to be not only a sufficient amount of time but a 
maximum amount of time allowable for existing stationary sources to 
install pollution controls as necessary for expeditious attainment, to 
eliminate prohibited interstate transport of pollutants, and to protect 
public health.
    Further, the EPA notes that, given the number of years that have 
passed since EPA's promulgation of the 2015 ozone NAAQS and related 
nonattainment area designations in 2018, and in light of the Maryland 
court's holding that good neighbor obligations for the 2015 ozone NAAQS 
should have been implemented by the Marginal area attainment date in 
2021,\221\ many states are substantially delayed in implementing their 
good neighbor obligations for these NAAQS, and the sources proposed for 
NOX emissions control in this rule have continued to operate 
for several years without the controls necessary to eliminate their 
significant contribution to ongoing and persistent ozone nonattainment 
and maintenance problems in other states. Under these circumstances, we 
find it more than reasonable to require compliance with the control 
requirements for all non-EGUs and the EGU reductions related to post-
combustion control retrofit identified in Section VI.B.1.b of this 
proposed rule by the beginning of the 2026 ozone season (i.e., by May 
1, 2026). May 1, 2026, is more than 3 years after the date by which the 
EPA currently anticipates promulgating a final FIP for the covered 
states, more than three years after the January 1, 2023, deadline for 
implementation of section 182 RACT SIP provisions in areas classified 
as Moderate or higher, and almost 8 years after the October 1, 2018, 
deadline for submission of good neighbor SIPs that prohibit significant 
contribution to nonattainment or interference with maintenance in 
downwind states.\222\
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    \221\ 958 F.3d at 1203-1204 (remanding the EPA denial of section 
126 petition based on the EPA analysis of downwind air quality in 
2023 rather than 2021, the year containing the Marginal area 
attainment date).
    \222\ CAA sections 110(a)(1) and 110(a)(2)(D)(i) (requiring 
states to submit, within 3 years after EPA's promulgation of a new 
or revised NAAQS, SIP provisions adequate to satisfy the Good 
Neighbor Provision). As the Supreme Court noted in EME Homer City I, 
``nothing in the statute places EPA under an obligation to provide 
specific metrics to States before they undertake to fulfill their 
good neighbor obligations.'' 572 U.S. 489, 510.
---------------------------------------------------------------------------

    As the D.C. Circuit noted in Wisconsin, the good neighbor provision 
requires upwind states to ``eliminate their substantial contributions 
to downwind nonattainment in concert with the attainment deadlines'' in 
the downwind states, even where those attainment deadlines occur before 
EPA's statutory deadline to promulgate a FIP.\223\ Referencing the 
Supreme Court's description of the attainment deadlines as ``the 
heart'' of the CAA, the Wisconsin court noted that some deviation from 
the mandate to eliminate prohibited transport by downwind attainment 
deadlines may be allowed only ``under particular circumstances and upon 
a sufficient showing of necessity,'' e.g., when compliance with the 
statutory mandate amounts to an impossibility.\224\
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    \223\ 938 F.3d at 317-318. For example, the court observed that 
the EPA may shorten the deadline for SIP submissions under CAA 
section 110(a)(1) and may issue FIPs soon thereafter under CAA 
section 110(c)(1), to align the upwind states' deadline for 
satisfying good neighbor obligations with the downwind states' 
deadline for attaining the NAAQS. Id. at 318.
    \224\ Id. at 316 and 319-320 (noting that any such deviation 
must be ``rooted in Title I's framework'' and ``provide a sufficient 
level of protection to downwind States'').
---------------------------------------------------------------------------

    For the reasons provided below in this section, the EPA is 
proposing to find that installation of certain EGU controls and all 
non-EGU controls is not possible by the Moderate area attainment date 
for the 2015 ozone NAAQS (i.e., August 3, 2024),\225\ and that the 2026 
ozone season, which corresponds to the August 3, 2027, Serious area 
attainment date for these NAAQS, is the earliest downwind attainment 
date by which the required emissions reductions from these strategies 
are possible.
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    \225\ Compliance by the August 3, 2021, Marginal area attainment 
date is also impossible as that date has passed.
---------------------------------------------------------------------------

a. EGU Schedule for 2026 and Later Years
    As discussed in Sections VI.B through VI.D of this proposed rule, 
significant emissions reduction potential exists and is included in 
EPA's quantification of significant contribution based on the potential 
to install post-combustion controls (SCR and SNCRs) at EGUs. However, 
as discussed in detail in those sections, the assumption for 
installation of this technology on a region-wide scale is 36 months in 
this proposed rule. This amount of time allows for all necessary 
procurement, permitting, and installation milestones across multiple 
units in the covered region. Therefore, the EPA proposes to find that 
these emissions reductions are not available any earlier than the 2026 
compliance period. For each year in 2026 and beyond, state emissions 
budgets include reductions commensurate with these post-combustion 
control technologies identified for covered units in Step 3. The EPA 
notes that similar compliance schedules and post-combustion control 
retrofit installations have been realized successfully in prior 
programs allowing similar timeframes. Subsequent to the NOX 
SIP Call and the parallel Finding of Significant Contribution and 
Rulemaking on Section 126 Petitions (which became effective December 
28, 1998, and February 17, 2000, respectively \226\), nearly 19 GW of 
SCR

[[Page 20103]]

retrofit came online in 2002 and another 42 GW of SCR retrofit came 
online for steam boilers in 2003, illustrating that a considerable 
volume of SCR retrofit capacity is possible in a 36 month period.
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    \226\ See 63 FR 57356 (October 27, 1998); 65 FR 2674 (January 
18, 2000). The D.C. Circuit stayed the NOX SIP Call by an 
order issued May 25, 1999. After upholding the rule in most respects 
in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000), the court lifted 
the stay by an order issued June 22, 2000.
---------------------------------------------------------------------------

    However, the EPA is not proposing to apply daily emissions rates on 
coal-fired steam EGUs assumed to retrofit SCR until 2027 (as described 
in Section VII.B.1.c.i of this proposed rule). The EPA believes that 
implementing these emissions reductions at the state level starting in 
2026 (through state emissions budgets) while imposing the unit-specific 
emissions rate limits in 2027 achieves the necessary environmental 
performance as soon as possible while accommodating any heterogeneity 
in unit-level implementation schedules regarding installation of new 
SCR.\227\
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    \227\ However, as discussed in Section VII.B.1.c.i of this 
proposed rule, EPA's determinations in this regard are not based on 
a finding that the retrofit of post-combustion controls would not be 
feasible in the 2026 ozone season for all relevant units. The EPA 
finds that such retrofits are available and feasible on a fleetwide 
scale starting in the 2026 ozone season.
---------------------------------------------------------------------------

b. Non-EGU Schedule for 2026 and Later Years
    For the suite of non-EGU controls on which the EPA has based its 
Step 3 findings as described in Section VI of this proposed rule, the 
EPA proposes to require that these controls be installed and 
operational by the 2026 ozone season and to find that any earlier date 
is not possible. The EPA previously examined the time necessary to 
install the controls identified for several non-EGU industries. 
Although the information on installation times for most NOX 
controls applied to glass and cement manufacturing was uncertain, the 
EPA identified minimum estimated installation times for a number of 
other non-EGU source categories that ranged from several weeks to 
slightly over a year. This included timeframes of 42-51 weeks for SNCR 
applied to dry cement manufacturing facilities and cement kilns/dryers 
burning bituminous coal, 28-58 weeks for SCR applied to boilers and 
process heaters, 28-58 weeks for SCR applied to iron and steel in-
process combustion, and 6-8 months for low NOX burners and 
flue gas recirculation at iron and steel mills.\228\ Taking into 
account necessary scale-up of construction services for multiple 
control installations at several emissions units, the time needed to 
have NOX monitoring installed and operating, and other 
necessary steps in the permitting and construction processes (e.g., 
review of vendor bids), the EPA estimates an additional period of 6 to 
18 months may be necessary for existing non-EGU sources to install the 
necessary controls, depending on the number of control installations at 
a facility.\229\
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    \228\ Final Technical Support Document (TSD) for the Final 
Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment 
of Non-EGU NOX Emissions Controls, Cost of Controls, and 
Time for Compliance Final TSD (``CSAPR Update Non-EGU TSD''), August 
2016 (Table 3), available at https://www.epa.gov/csapr/assessment-non-egu-NOX-emission-controls-cost-controls-and-time-compliance-
final-tsd. See also Institute of Clean Air Companies, SNCR 
Committee, ``White Paper, Selective Non-Catalytic Reduction (SNCR) 
For Controlling NOX Emissions,'' at 5 (noting that ``SNCR 
retrofits typically do not require extended source shutdowns'').
    \229\ 63 FR 57356, 57448 (October 27, 1998). EPA generally 
anticipates that any required permitting processes may run 
concurrent with other steps in the installation processes and thus 
may not significantly lengthen the total time needed for 
installation.
---------------------------------------------------------------------------

    Additionally, the EPA previously considered the installation timing 
needs for NOX controls (including SCR, SNCR, and combustion 
controls) at both EGU and non-EGU sources as part of the 1998 
NOX SIP Call.\230\ With respect to combustion controls 
(e.g., low-NOX burners, overfire air, etc.), the EPA found 
that sources should be able to complete control technology 
installations and obtain relevant permits in relatively short 
timeframes given considerable experience at that time among sources and 
permitting agencies with the implementation of such controls, the fact 
that combustion controls are constructed of commonly available 
materials (steel, piping, etc.) and do not require reagent during 
operation, and the then availability of many vendors of combustion 
control technology.\231\
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    \230\ Id. at 57447-57449.
    \231\ Id. at 57447, 57449.
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    With respect to post-combustion controls (primarily SCR and SNCR), 
the EPA considered three basic factors in assessing installation timing 
needs: (1) Availability of materials and labor, (2) the time needed to 
implement controls at plants with single or multiple retrofit 
requirements, and (3) the potential for interruptions in power supply 
resulting from outages needed to complete installations on EGUs.\232\ 
Assuming adequate supplies of both off-the-shelf hardware (such as 
steel, piping, nozzles, pumps, and related equipment) and the catalyst 
used in the SCR process, as well as sufficient vendor capacity to 
supply retrofit SCR catalyst to sources, and taking into account the 
additional time needed for facility engineering review, developing 
control technology specifications, awarding a procurement contract, 
obtaining a construction permit, completing control technology design, 
installation, and testing, and obtaining an operating permit, the EPA 
found that (a) about 21 months would be needed to implement an SCR 
retrofit on a single unit and (b) about 19 months would be needed to 
implement an SNCR retrofit on a single unit.\233\ The EPA also examined 
several particularly complicated implementation efforts and found that 
34 months would be needed for a plant to install a maximum of 6 SCRs 
while 24 months would be needed for a plant to install a maximum of 10 
SNCRs.\234\ Finally, the EPA found that the necessary controls could be 
installed on EGUs without any disruptions in the supply of electricity 
because connections between a NOX control system and a 
boiler can generally be completed in 5 weeks or less and thus could 
occur during the 5-week planned outage that each EGU typically has each 
year.\235\
---------------------------------------------------------------------------

    \232\ Id. at 57448.
    \233\ Id.
    \234\ Id.
    \235\ Id.
---------------------------------------------------------------------------

    Thus, for both EGUs and non-EGUs, EPA's technical analysis for the 
1998 NOX SIP Call indicated that a 3-year period would be 
sufficient for installation of both combustion and post-combustion 
controls, from the planning and specification of controls to completion 
of control technology implementation.\236\ EPA's evaluation of the 
timeframes for post-combustion controls was based on the Agency's 
projection that 639 retrofit installations at EGU sources and 235 
retrofit installations at non-EGU industrial sources would be necessary 
for existing sources in the covered states to comply with the 
NOX SIP Call.\237\ Although the scope of types of non-EGU 
sources covered by this proposed FIP is broader, and the estimated 
number of emissions units is greater (potentially including as many as 
490 emissions units), than the scope and number of non-EGU sources 
evaluated in the 1998 NOX SIP Call, and although a later 
analysis of timeframes for installation of post-combustion controls at 
EGUs produced a more refined estimate for that sector only,\238\ EPA's 
prior analyses nonetheless inform the evaluation in this proposal of 
the necessary implementation schedule for non-EGU sources given they 
generally address NOX control technologies similar to those 
that the EPA anticipates non-EGU sources may install to comply with the 
provisions of the proposed FIP

[[Page 20104]]

(e.g., SCR, SNCR, low-NOX burners and ultra-low 
NOX burners).
---------------------------------------------------------------------------

    \236\ Id. at 57449.
    \237\ Id. at 57448 (Table V-1 and Table V-2).
    \238\ See Final Report, ``Engineering and Economic Factors 
Affecting the Installation of Control Technologies for 
Multipollutant Strategies,'' EPA-600/R-02/073 (October 2002).
---------------------------------------------------------------------------

    Additionally, as part of EPA's evaluation of installation timing 
needs in the proposed CAIR (69 FR 4566), the EPA projected that it 
would take on average 21 months to install an SCR on one EGU unit, 27 
months to install a scrubber on one EGU unit, and 3 years to install 
seven SCRs at a single EGU.\239\ The EPA also noted that some EGUs 
could install SCR controls in as short of a period as 13 months.\240\ 
This information and EPA's general experience indicate that a two-year 
installation timeframe for a rule requiring installation of new control 
technologies across a variety of emissions sources in several 
industries on a regional basis is a relatively fast installation 
timeframe, but that a 3-year installation timeframe should be feasible 
for most if not all of the identified industries. A shorter 
installation timeframe of approximately one year would likely raise 
significant challenges for sources, suppliers, contractors, and other 
economic actors, potentially including customers relying on the 
products or services supplied by the regulated sources. Thus, if the 
EPA finalizes this proposed rule in 2023, implementation of the 
necessary emissions controls across all of the affected non-EGU sources 
by the August 3, 2024, Moderate area attainment date would not be 
possible.
---------------------------------------------------------------------------

    \239\ 69 FR 4566, 4617 (January 30, 2004) (citing Final Report, 
``Engineering and Economic Factors Affecting the Installation of 
Control Technologies for Multipollutant Strategies,'' EPA-600/R-02/
073 (October 2002)).
    \240\ Final Report, ``Engineering and Economic Factors Affecting 
the Installation of Control Technologies for Multipollutant 
Strategies,'' EPA-600/R-02/073 (October 2002), at 21.
---------------------------------------------------------------------------

    For purposes of this proposed rule, the EPA estimates that the 
required controls for non-EGU source categories would take up to 3 
years to install across the affected industries in the 23 states that 
remain linked in 2026. Therefore, based on the available information, 
the EPA proposes to require compliance with these non-EGU control 
requirements by the beginning of the 2026 ozone season.
    The EPA requests comment on the time needed to install the various 
control technologies across all of the emissions units in the Tier 1 
and Tier 2 industries. In particular, the EPA solicits comment on the 
time needed to obtain permits (including the potential applicability of 
NSR requirements), the availability of vendors and materials, design, 
construction, and the earliest possible installation times for SCR on 
glass furnaces; SNCR or SCR on cement kilns; ultra-low NOX 
burners, low NOX burners, and SCR on ICI boilers (coal-
fired, gas-fired, or oil-fired); low NOX burners on large 
non-EGU ICI boilers; and low emissions combustion, layered emissions 
combustion, NSCR, and SCR on reciprocating rich-burn or lean-burn IC 
engines.
    With respect to emissions monitoring requirements, EPA requests 
comment on the costs of installing and operating CEMS at non-EGU 
sources without NOX emissions monitors; the time needed to 
program and install CEMS at non-EGU sources; whether monitoring 
techniques other than CEMS, such as predictive emissions monitoring 
systems (PEMS), may be sufficient for certain non-EGU facilities, and 
the types of non-EGU facilities for which such PEMS may be sufficient; 
and the costs of installing and operating monitoring techniques other 
than CEMS.
    The EPA also requests comment on whether the FIP should provide a 
limited amount of time beyond the 2026 ozone season for individual non-
EGU sources to meet the emissions limitations and associated compliance 
requirements, based on a facility-specific demonstration of necessity. 
As the D.C. Circuit stated in Wisconsin, the good neighbor provision 
may be read to allow for some deviation from the mandate to eliminate 
prohibited transport by downwind attainment deadlines, ``under 
particular circumstances and upon a sufficient showing of necessity,'' 
provided such deviation is ``rooted in Title I's framework [and] 
provide[s] a sufficient level of protection to downwind States.'' \241\ 
Consistent with this directive, and recognizing that in general, the 
EPA aligns good neighbor obligations in the first instance with the 
last full ozone season before the downwind attainment date, the EPA 
requests comment on whether individual non-EGU sources should be 
allowed to request an extension of the May 1, 2026, compliance deadline 
by no more than 1 year (i.e., to May 1, 2027) based on a sufficient 
showing of necessity. Any such comments should be supported by a 
detailed discussion of the facility-specific economic, technological, 
and other circumstances that may justify such an extension. The EPA 
notes that claims about infeasibility of controls are generally 
insufficient to justify an extension of time to comply, given the 
Wisconsin court's holding that the good neighbor provision requires 
upwind states to eliminate their significant contribution in accordance 
with the downwind states' attainment deadlines, without regard to 
questions of feasibility.\242\
---------------------------------------------------------------------------

    \241\ Wisconsin, 938 F. 3d at 320 (citing CAA section 181(a) 
(allowing one-year extension of attainment deadlines in particular 
circumstances) and North Carolina, 531 F.3d at 912).
    \242\ Wisconsin, 938 F.3d at 313-314, 319 (``When an agency 
faces a statutory mandate, a decision to disregard it cannot be 
grounded in mere infeasibility''). We note also that in the CSAPR 
Close-Out Rule (83 FR 65878, December 21, 2018), the EPA required no 
further reductions from upwind states beyond those set forth in the 
prior CSAPR Update based, in part, on the Agency's conclusion that 
it was not feasible to implement cost-effective emissions controls 
before 2023, 2 years after the 2021 attainment deadline for the 
downwind serious areas. The D.C. Circuit vacated the Close-Out Rule 
for its reliance on the same interpretation of the Good Neighbor 
Provision that the court had rejected in Wisconsin. New York v. EPA, 
781 F. App'x 4 (D.C. Cir. 2019) (unpublished opinion).
---------------------------------------------------------------------------

    The EPA solicits comment on the specific criteria that the EPA 
should apply in evaluating requests for extension of the 2026 
compliance deadline for non-EGU sources. Such criteria could include 
documentation of inability, despite best efforts, to procure necessary 
materials or equipment (e.g., equipment manufacturers are not able to 
deliver equipment before a specific date) or hire labor as needed to 
install the emissions control technology by 2026; documentation of 
installation costs well in excess of the highest representative cost-
per ton threshold identified for any source (including EGUs) discussed 
in Section VI of this proposed rule (e.g., vendor estimate showing 
equipment cost); documentation of a source owner or operator's 
inability to secure necessary financing, due to circumstances beyond 
the owner/operator's control, in time to complete the installation of 
controls by 2026; or documentation of extreme financial or 
technological constraints that would require the subject non-EGU 
emissions unit or facility to significantly curtail its operations or 
shut down before it could comply with the requirements of this proposed 
rule by 2026. Finally, the EPA requests comment on the process through 
which the EPA should review and act on an extension request--e.g., the 
appropriate deadline for submitting a request, and whether the EPA 
should provide an opportunity for public comment before granting or 
denying a request.
    The EPA anticipates that the owner or operator of the facility 
would bear the burden of establishing the necessity of an extension of 
time to comply, based on particular circumstances described and 
sufficiently documented in the submitted request. Claims of generalized 
financial or economic hardship or any claim that controls are not 
necessary to eliminate significant contribution would

[[Page 20105]]

not suffice to justify an extension. If the EPA finalizes a provision 
allowing sources to request limited extensions of time to comply, the 
Agency would review each request on a case-by-case basis as necessary 
to ensure consistency with the provisions of title I of the CAA.

B. Regulatory Requirements for EGUs

    To implement the required emissions reductions from EGUs, the EPA 
proposes to revise the existing CSAPR NOX Ozone Season Group 
3 Trading Program (the ``Group 3 trading program'') established in the 
Revised CSAPR Update both to expand the program's geographic scope and 
to enhance the program's ability to ensure favorable environmental 
outcomes.\243\ The EPA proposes to use a trading program for EGUs 
because of the inherently greater flexibility that a trading program 
can provide relative to more prescriptive, ``command-and-control'' 
forms of regulation of sufficient stringency to achieve the necessary 
emissions reductions. In the electric power sector, EGUs' extensive 
interconnectedness and coordination create the ability to shift both 
electricity production and emissions among units, providing a closely 
related ability to achieve emissions reductions in part by shifting 
electricity production from higher-emitting units to lower-emitting or 
non-emitting units. The sector's unusual flexibility with respect to 
how emissions reductions can be achieved makes the flexibility of a 
trading program particularly useful as a means of lowering the overall 
costs of obtaining such reductions. In addition, it is essential for 
the electric power sector to retain short-term operational flexibility 
sufficient to allow electricity to be produced at all times in the 
quantities needed to meet demand simultaneously, and the flexibility of 
a trading program can be helpful in supporting this aspect of the 
industry as well. As discussed later, to provide improved environmental 
outcomes, in this rulemaking, the EPA is proposing certain enhancements 
to the current provisions of the Group 3 trading program addressing 
environmental performance that will necessarily reduce the flexibility 
of the individual units participating in the program to some extent. 
However, with the proposed enhancements, the EPA believes the 
inherently greater flexibility of a trading program continues to favor 
the use of this form of regulation, relative to more prescriptive forms 
of regulation, as a vehicle for achieving the emissions reductions from 
the electric power sector found to be necessary in this rulemaking.
---------------------------------------------------------------------------

    \243\ If any of the states whose sources currently participate 
in the Group 3 trading program is determined in the final rule to 
not have additional emissions reduction requirements for EGUs, the 
EPA proposes in the alternative to establish a new trading program 
substantially similar to the revised Group 3 trading program 
described in this proposal that would cover units within the borders 
of all the states determined to have emissions reduction 
requirements for EGUs in the final rule.
---------------------------------------------------------------------------

    The Group 3 trading program currently applies to EGUs meeting the 
program's applicability criteria within the borders of twelve states: 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, 
New York, Ohio, Pennsylvania, Virginia, and West Virginia. Affected 
EGUs in these twelve states would continue to participate in the Group 
3 trading program as revised in this rulemaking, with some revised 
provisions taking effect in the 2023 control period and other revised 
provisions taking effect later as discussed elsewhere in this document. 
The EPA proposes to expand the Group 3 trading program's geographic 
scope to include all of the additional states for which EGU emissions 
reduction requirements are being established in this rulemaking. 
Affected EGUs within the borders of eight states currently covered by 
the CSAPR NOX Ozone Season Group 2 Trading Program (the 
``Group 2 trading program'')--Alabama, Arkansas, Mississippi, Missouri, 
Oklahoma, Tennessee, Texas, and Wisconsin--would transition from the 
Group 2 program to the revised Group 3 trading program at the beginning 
of the 2023 control period,\244\ and affected EGUs within the borders 
of the five states not currently covered by any CSAPR trading program 
for seasonal NOX emissions--Delaware, Minnesota, Nevada, 
Utah, and Wyoming--would enter the Group 3 trading program in the 2023 
control period following the effective date of a final rule in this 
rulemaking. As is the case for the states already in the Group 3 
trading program, for each state added to the program, the set of 
affected EGUs would include new units as well as existing units and 
units located in Indian country within the state's borders as well as 
units not located in Indian country. Sections VII.B.2 and VII.B.3 of 
this proposed rule provide additional discussion of the proposed 
geographic expansion of the Group 3 trading program and the units in 
the expanded geography that would likely become subject to the program 
under the program's existing applicability provisions.
---------------------------------------------------------------------------

    \244\ Affected EGUs in the two other states currently covered by 
the Group 2 trading program--Iowa and Kansas--would continue to 
participate in that program.
---------------------------------------------------------------------------

    In addition to expanding the Group 3 trading program's geographic 
scope, the EPA proposes to modify the program's regulations 
prospectively to include certain enhancements to improve environmental 
outcomes. Two of the proposed enhancements would adjust the overall 
quantities of allowances available for compliance in the trading 
program in each control period so as to maintain the rule's selected 
control stringency and related EGU effective emissions rate performance 
level as the EGU fleet evolves. First, instead of establishing 
emissions budgets for all future years under the program at the time of 
the rulemaking, which cannot reflect future changes in the EGU fleet 
unknown at the time of the rulemaking, the EPA proposes to revise the 
trading program regulations to include a dynamic budgeting procedure. 
This procedure would calculate emissions budgets for control periods in 
2025 and later years based on more current information about the 
composition and utilization of the EGU fleet, specifically data 
available from the 2023 ozone season and following (e.g., for 2025, 
data from 2023; for 2026, data from 2024; etc.). (Associated revisions 
to the program's variability limits and unit-level allowance allocation 
procedures would coordinate these provisions with the revised budget-
setting procedures.) Second, starting with the 2024 control period, the 
EPA proposes to annually recalibrate the quantity of accumulated banked 
allowances under the program to prevent the quantity of allowances 
carried over from each control period to the next from exceeding the 
target bank level, which would be revised to represent 10.5 percent of 
the sum of the state emissions budgets. Together, these enhancements 
would protect the intended stringency of the trading program against 
potential erosion caused by EGU fleet turnover and would better sustain 
over time the incentives created by the trading program to apply 
continuously the degree of emissions control the EPA determines is 
necessary to address states' good neighbor obligations.
    Two further enhancements to the Group 3 trading program proposed in 
this rulemaking would establish provisions designed to promote more 
consistent emissions control by individual EGUs within the context of 
the trading program. First, starting with the 2024 control period for 
most coal-fired EGUs with existing SCR controls and the 2027 control 
period for most other coal-fired EGUs, a daily NOX emissions 
rate of 0.14 lb/mmBtu would

[[Page 20106]]

apply as a backstop to the more stringent seasonal emissions budgets. 
Each ton of emissions exceeding a unit's backstop daily emissions rate 
would incur a 3-for-1 allowance surrender ratio instead of the usual 1-
for-1 allowance surrender ratio. Second, also starting with the 2024 
control period, the trading program's existing assurance provisions, 
which require extra allowance surrenders from sources that are found 
responsible for contributing to an exceedance of the relevant state's 
``assurance level'' (i.e., currently 121 percent of the state's 
emissions budget), would be strengthened by the addition of another 
backstop requirement. Specifically, for any unit found responsible for 
contributing to an exceedance of the state's assurance level, the 
revised regulations would prohibit the unit's seasonal emissions from 
exceeding by more than 50 tons the emissions that would have resulted 
if the unit had achieved a seasonal average emissions rate equal to the 
higher of 0.10 lb/mmBtu or 125 percent of the unit's lowest previous 
seasonal average emissions rate under any CSAPR seasonal NOX 
trading program.\245\
---------------------------------------------------------------------------

    \245\ The requirement would not apply for control periods during 
which the unit operated for less than 10 percent of the hours, and 
emissions rates achieved in such previous control periods would be 
excluded from the comparison.
---------------------------------------------------------------------------

    These two enhancements are designed to ensure that all individual 
units with SCR controls have strong incentives to continuously operate 
and optimize their controls, and also to ensure that even units without 
SCR controls have strong incentives to optimize their emissions 
performance when a state's assurance level might otherwise be exceeded. 
These enhancements are generally designed to ensure consistency with 
EPA's determination regarding the emissions control stringency needed 
from EGUs to eliminate significant contribution under the Step 3 
multifactor analysis as discussed in Section VI of this proposed rule. 
Further, these enhancements are designed to provide greater assurance 
that emissions controls will be operated on all days of the ozone 
season and therefore necessarily on the days that turn out to be most 
critical for downwind ozone levels. The EPA expects that promoting more 
consistently good emissions performance by individual EGUs will also 
help address disparate impacts of pollution on overburdened communities 
from individual units that might otherwise have chosen not to optimize 
their emissions performance.
1. Trading Program Background and Overview of Proposed Revisions
a. Current CSAPR Trading Program Design Elements and Identified 
Concerns
    The use of allowance trading programs to achieve required emissions 
reductions from the electric power sector has a long history, rooted in 
the Clean Air Act Amendments of 1990. In Title IV of those amendments, 
Congress specified the design elements for a 48-state allowance trading 
program to reduce SO2 emissions and the resulting acid 
precipitation. Building on the success of that first allowance trading 
program as a tool for addressing multi-state air pollution issues, 
since 1998 EPA has promulgated and implemented multiple allowance 
trading programs for SO2 or NOX emissions to 
address the requirements of the CAA's good neighbor provision with 
respect to successively more stringent NAAQS for fine particulate 
matter and ozone. Most of these trading programs have applied either 
exclusively or primarily to EGUs.
    The EPA currently administers six CSAPR trading programs for EGUs 
(promulgated in CSAPR, the CSAPR Update, and the Revised CSAPR Update) 
that differ in the pollutants, geographic regions, and time periods 
covered and in the levels of stringency, but that otherwise are nearly 
identical in their core design elements and their regulatory text.\246\ 
The principal common design elements currently reflected in all of the 
programs are as follows:
---------------------------------------------------------------------------

    \246\ The six current CSAPR trading programs are the CSAPR 
NOX Annual Trading Program, CSAPR NOX Ozone 
Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading 
Program, CSAPR SO2 Group 2 Trading Program, CSAPR 
NOX Ozone Season Group 2 Trading Program, and CSAPR 
NOX Ozone Season Group 3 Trading Program. The regulations 
for the six programs are set forth at subparts AAAAA, BBBBB, CCCCC, 
DDDDD, EEEEE, and GGGGG, respectively, of 40 CFR part 97.
---------------------------------------------------------------------------

     An ``emissions budget'' is established for each state for 
each control period, representing EPA's quantification of the emissions 
that would remain under certain projected conditions after elimination 
of the emissions prohibited by the good neighbor provision under those 
projected conditions. For each control period of program operation, a 
quantity of newly issued ``allowances'' equal to the amount of each 
state's emissions budget is allocated among the state's sources. 
(States have options to replace EPA's default allocations or to 
institute an auction process.) Total emissions in a given control 
period from all sources in the program are effectively capped at a 
level no higher than the total quantity of allowances available for use 
in the control period, consisting of the sum of all states' emissions 
budgets for the control period plus any unused allowances carried over 
from previous control periods as ``banked'' allowances.
     ``Assurance provisions'' in each program establish an 
``assurance level'' for each state for each control period, defined as 
the sum of the state's emissions budget plus a specified ``variability 
limit.'' The purpose of the assurance provisions is to limit the total 
emissions from each state's sources in each control period to an amount 
close to the state's emissions budget for the control period, 
consistent with the good neighbor provision's mandate that required 
emissions reductions must be achieved within the state, while allowing 
some flexibility beyond the emissions budget to accommodate year-to-
year operational variability. In the event a state's assurance level is 
exceeded, responsibility for the exceedance is apportioned among the 
state's sources through a procedure that accounts for the sources' 
shares of the state's total emissions for the control period as well as 
the sources' shares of the state's assurance level for the control 
period.
     At the program's compliance deadlines after each control 
period, sources are required to hold for surrender specified quantities 
of allowances. The minimum quantities of allowances that must be 
surrendered are based on the sources' reported emissions for the 
control period at a 1-for-1 ratio of allowances to tons of emissions 
(or 2-for-1 in instances of late compliance). In addition, two more 
allowances must be surrendered for each ton of emissions exceeding a 
state's assurance level for a control period, yielding an overall 3-
for-1 surrender ratio for those emissions (or 4-for-1 in instances of 
late compliance). Failure to timely surrender all required allowances 
is potentially subject to penalties under the CAA's enforcement 
provisions.
     To continuously incentivize sources to reduce their 
emissions even when they already hold sufficient allowances to cover 
their expected emissions for a control period, and to promote 
compliance cost minimization, operational flexibility, and allowance 
market liquidity, the programs allow trading of allowances--both among 
sources in the program and with non-source entities--and also let 
allowances that are unused in one control period be carried over for 
use in future control periods as banked allowances. Although the 
programs do not directly limit either trading or banking of allowances, 
the 3-for-1 surrender ratio imposed by the

[[Page 20107]]

assurance provisions on any emissions exceeding a state's assurance 
level disincentivizes sources from relying on either in-state banked 
allowances or net out-of-state purchased allowances to emit over the 
assurance level.
     Finally, other common design elements ensure program 
integrity, source accountability, and administrative transparency. Most 
notably, each unit must monitor and report emissions and operational 
data in accordance with the provisions of 40 CFR part 75; all allowance 
allocations or auction results, transfers, and deductions must be 
properly recorded in EPA's Allowance Management System; each source 
must have a designated representative who is authorized to represent 
all of the source's owners and operators and is responsible for 
certifying the accuracy of the source's reports to the EPA and 
overseeing the source's Allowance Management System account; and 
comprehensive data on emissions and allowances are made publicly 
available.
    The EPA continues to believe that the current CSAPR trading program 
structure established by the common design elements described 
previously has important positive attributes, particularly with respect 
to the exceptional degree of compliance flexibility it can provide to a 
sector such as the electric power sector where such flexibility is 
especially useful and valuable. However, the EPA also shares some 
stakeholders' concerns about whether the current structure, without 
enhancements, is capable of adequately addressing states' good neighbor 
obligations with respect to the 2015 ozone NAAQS in light of the 
rapidly evolving EGU fleet and the stringency and short-term form of 
the standard. One set of concerns relates to the observed tendency 
under the current trading programs for the supply of allowances to grow 
over time while the demand for allowances falls, reducing allowance 
prices and eroding the consequent incentives for sources to effectively 
control their emissions. A second, overlapping set of concerns relates 
to the general absence of source- or unit-specific emissions reduction 
requirements, allowing some individual sources to idle existing 
emissions controls. Emissions from these individual sources can 
contribute to increased pollution concentrations downwind on the 
particular days that matter for downwind exceedances of the relevant 
air quality standard and also have the potential to cause 
disproportionate adverse impacts on downwind overburdened communities. 
The EPA has analyzed hourly emissions data reported in prior cap-and-
trade programs and identified instances of sources that did not operate 
SCR controls for substantial portions of recent ozone seasons. In an 
effort to maintain as much compliance and operational flexibility as 
possible, ensure controls happen on critically important highest ozone 
days, guard against this behavior under a more stringent NAAQS, and 
provide relief to overburdened communities, the EPA would require 
control operation every day through a unit-level emission rate designed 
to ensure reductions occur on the highest ozone days in addition to 
maintaining a mass-based seasonal requirement. To meet the statutory 
requirement to eliminate significant contribution and interference with 
maintenance on the critically important days, this combination of 
requirements would require sources to plan to run controls all season, 
including the highest ozone days, while giving reasonable flexibility 
for occasional operational needs.
    In this rulemaking, the EPA is proposing to revise the Group 3 
trading program to include enhancements designed to address both sets 
of concerns described above.\247\ The principles guiding the various 
proposed revisions and the relationships of the revisions to one 
another are discussed in Sections VII.B.1.b and VII.B.1.c of this 
proposed rule. The individual proposed revisions are discussed in more 
detail in Sections VII.B.4 through VII.B.9 of this proposed rule.
---------------------------------------------------------------------------

    \247\ With the exception of the proposed conforming revisions to 
allowance recordation schedules discussed in Section VII.B.12 of 
this proposed rule, the EPA is not proposing in this rulemaking to 
extend the enhancements proposed for the Group 3 trading program to 
the other CSAPR trading programs.
---------------------------------------------------------------------------

b. Enhancements To Maintain Selected Control Stringency Over Time
    The first set of concerns noted about the current CSAPR trading 
program structure relates to the programs' ability to maintain the 
rule's selected control stringency and related EGU effective emissions 
rate performance level as the EGU fleet evolves over time. Under the 
structure of the current CSAPR trading programs, the effectiveness of 
the programs at maintaining the rule's selected control stringency 
depends entirely on how allowance prices over time compare to the costs 
of sources' various emissions reduction opportunities, which in turn 
depends on the relationship between the supply for allowances and the 
demand for allowances. In considering possible ways to address concerns 
about the ability to enhance the current trading program structure to 
better sustain incentives to control emissions over time, the EPA has 
focused on the trading program design elements that determine the 
supply of allowances, specifically the approach for setting state 
emissions budgets and the rules concerning the carryover of unused 
allowances for use in future control periods as banked allowances.
i. Revised Emissions Budget-Setting Process
    In each of the previous rulemakings establishing CSAPR trading 
programs, the EPA has evaluated the emissions that could be eliminated 
through implementation of certain types of emissions control strategies 
available at various cost thresholds to achieve certain rates of 
emissions per unit of heat input (i.e., the amount of fuel consumed) 
and the effects of the resulting emissions reductions on downwind air 
quality. After determining the emissions control strategies and 
associated emissions reductions that should be required under the good 
neighbor provision by considering these factors in a multifactor test, 
the EPA has then projected the amounts of emissions that would remain 
after the assumed implementation of the selected emissions control 
strategies at various points in the future and has established the 
projected remaining amounts of emissions as the state emissions budgets 
in trading programs.
    Projecting the amounts of emissions remaining after implementation 
of selected emissions controls necessarily requires projections not 
only for sources' future emissions rates but also for other factors 
that influence total emissions, notably the composition of the future 
EGU fleet (i.e., the capacity amounts of different types of sources 
with different emissions rates) and their future utilization levels 
(i.e., their heat input). To the extent the projections made at the 
time of a rulemaking for these other factors prove inaccurate, over 
time the emissions budgets may not reflect the intended stringency of 
the emissions control strategies identified in the rulemaking as 
consistent with addressing states' good neighbor obligations. Further, 
projecting EGU fleet composition and utilization has become 
increasingly challenging in light of the rapid evolution of the 
electric power sector toward more efficient and cleaner sources of 
generation, driven by factors including lower prices for natural gas 
and wind and solar generation.

[[Page 20108]]

    A consequence of using a trading program approach with preset 
emissions budgets that do not keep pace with the trends in EGU fleet 
composition and heat input is that the preset emissions budgets 
maintain the supply of allowances at levels that increasingly exceed 
the emissions that would occur even without implementation of the 
emissions control strategies used as the basis for determining the 
emissions budgets, causing decreases in allowance prices and hence the 
incentives to implement the control strategies. As an example, although 
the emissions budgets in the CSAPR Update established in 2016 reflected 
implementation of the emissions control strategy of operating and 
optimizing existing SCR controls, within 4 years the EPA found that EGU 
retirements and changes in utilization not anticipated in EPA's 
previous budget-setting computations had made it economically 
attractive for at least some sources to idle or reduce the 
effectiveness of their existing controls (relying on purchased 
allowances instead).\248\ While the EPA has provided analysis 
indicating that, on average, sources operate their controls more 
effectively on high electric demand days, it has also identified cases 
where units fail to optimize their controls on these days. Downwind 
states have suggested this type of reduced pollution control 
performance has occurred on the day and preceding day of an ozone 
exceedance.249 250 Such an outcome undermined the ongoing 
achievement of emissions rate performance consistent with the control 
strategies defined to eliminate significant contribution to 
nonattainment and interference with maintenance, including continuous 
operation and optimization of existing controls.
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    \248\ The price of allowances in CSAPR Update states started out 
at levels near $800 per ton in 2017 but declined to less than $100 
per ton by 2019 and were less than $70 per ton in July 2020 (data 
from S&P Global Market Intelligence).
    \249\ 86 FR 23117.
    \250\ See EPA-HQ-OAR-2020-0272-0094. ``. . . is demonstrated 
through examination of Maryland's ozone design value days for June 
26th-28th, 2019. On those days, Maryland recorded 8-hour ozone 
levels of 75, 85 and 83 ppb at the Edgewood monitor. Maryland 
Department of the Environment evaluated the daily NOX 
emission rate for units in Pennsylvania that were found to influence 
the design values on the 3 exceedance days (and 1 day prior to the 
exceedance) against the past-best ozone season 30-day rolling 
average optimized NOX rate (which tends to be higher than 
the absolute lowest seasonal average rate).''
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    In the Revised CSAPR Update, the EPA took steps to better address 
the rapid evolution of the EGU fleet, specifically by setting updated 
emissions budgets for individual future years though 2024 that reflect 
future EGU fleet changes known with reasonable certainty at the time of 
the rulemaking. Some commenters requested that the EPA also update the 
year-by-year emissions budgets to reflect future fleet changes that 
might become known after the time of the rulemaking, but the EPA 
declined to do so, in part because no methodology for making future 
emissions budget adjustments in response to post-rulemaking data had 
been included in the proposal for the rulemaking.
    Based on information available as of December 2021, it appears that 
the emissions budgets set for the first control period covered by the 
Revised CSAPR Update generally succeeded at creating incentives to 
operate emissions controls under the Group 3 trading program for the 
programs' first control period. However, the EPA recognizes that the 
lack of emissions budget adjustments after 2024 in conjunction with 
industry trends toward more efficient and cleaner resources would 
likely lead to a surplus of allowances after the adjustments end. In 
this rulemaking, besides setting new emissions budgets for the 2023 and 
2024 control periods, the EPA also proposes to extend the Group 3 
trading program budget-setting methodology used in the Revised CSAPR 
Update to routinely set emissions budgets for each future control 
period in the year before that control period, with each emissions 
budget reflecting the latest available information on the composition 
and utilization of the EGU fleet at the time that emissions budget is 
determined.
    The current budget-setting methodology established in the Revised 
CSAPR Update and the proposed revisions are discussed in detail in 
Section VII.B.4 of this proposed rule and the Ozone Transport Policy 
Analysis Proposed Rule TSD. To summarize here, the Revised CSAPR 
Update's emissions budget-setting methodology includes three primary 
steps: (1) Establishment of a baseline inventory of EGUs adjusted for 
known retirements and new units, with heat input and emissions rate 
data for each EGU in the inventory based on recent historical data; (2) 
adjustment of the baseline data to reflect assumed emissions rate 
changes resulting from known new controls, known gas conversions, and 
implementation of the emissions control strategies used to determine 
states' good neighbor obligations; and (3) application of an increment 
or decrement to reflect the effect on emissions from projected 
generation shifting among the units in a state at the emissions 
reduction cost associated with the selected emissions control 
strategies. In this rulemaking, the EPA proposes to modify this 
methodology in two ways. First, the baseline EGU inventory and heat 
input data, but not the emissions rate data, would be updated for each 
control period using the most recent available reported data. For 
example, in early 2024, using the final data reported for 2023, the EPA 
would update the baseline inventory and heat input data used to 
determine state emissions budgets for the 2025 control period. Second, 
the EPA would not apply an increment or decrement to any state 
emissions budget for projected generation shifting associated with 
implementation of the selected control strategies, because any such 
shifting should already be reflected in the heat input data used to 
update the baseline.\251\
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    \251\ Emission reductions derived from generation shifting will 
be captured in the dynamic budgets in all cases. For the pre-set 
budget years it is estimated and incorporated through an additional 
calculation step. For dynamic budget years, it is directly 
incorporated through the inclusion of updated heat input data 
reflecting observed, compliance period generation shifting.
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    The EPA believes that the proposed revisions to the emissions 
budget-setting process would substantially improve the ability of the 
emissions budgets to keep pace with changes in the composition and 
utilization of the EGU fleet. The revised methodology would account for 
the electric power sector's overall trends toward more efficient and 
cleaner resources, both of which tend to decrease total heat input at 
affected EGUs. The revised methodology would also account for other 
factors that could lead to increased heat input in some states, such as 
generation shifting from other states or increases in electricity 
demand caused by rising electrification. The updating procedure would 
be specified in the program regulations and the computations, which 
would be straightforward, could be performed in a spreadsheet to 
deliver reliable results. EPA would provide public notice of the 
preliminary calculations and the data used by March 1 of the year 
preceding the control period and would provide an opportunity for 
submission of any objections to the data and preliminary calculations 
before finalizing the budgets for each control period by May 1 of the 
year before the control period to which those budgets apply. Thus, for 
example, sources and other stakeholders will have certainty by May 1, 
2024, of the emissions budgets that will be set for the 2025 control 
period that starts May 1, 2025.

[[Page 20109]]

    It bears emphasis that the annually updated information would 
concern only the composition and utilization of the EGU fleet and not 
the emissions rate data also used in the emissions budget computations. 
The emissions budget computations for all years would reflect only the 
specific emissions control strategies used to determine states' good 
neighbor obligations as determined in this rulemaking, along with fixed 
historical emissions rates for units that are not assumed to implement 
additional control strategies, thereby ensuring that the annual updates 
would eliminate emissions as determined to be required under the good 
neighbor provision. The stringency of the emissions budgets would 
simply reflect the stringency of the emissions control strategies 
determined in the Step 3 multifactor analysis and would do so more 
consistently over time than EPA's previous approach of computing 
emissions budgets for all future control periods at the time of the 
rulemaking.
    The proposed revisions to state emissions budgets and the budget-
setting process are discussed further in Section VII.B.4 of this 
proposed rule. Proposed coordinated revisions to the determination of 
state-level variability limits and assurance levels and to unit-level 
allowance allocations are discussed in Sections VII.B.5 and VII.B.9 of 
this proposed rule, respectively.
ii. Allowance Bank Recalibration
    Besides the levels of the emissions budgets, the second design 
element of the trading program structure that affects the supply of 
allowances in each control period, and that consequently also affects 
the ability of a trading program to maintain the rule's selected 
control stringency and related EGU effective emissions rate performance 
level as the EGU fleet evolves over time, is the set of rules 
concerning the carryover of unused allowances for use in future control 
periods as banked allowances. As noted previously, trading and banking 
of allowances in the CSAPR trading programs can serve a variety of 
purposes: Continuously incentivizing sources to reduce their emissions 
even when they already hold sufficient allowances to cover their 
expected emissions for a control period, facilitating compliance cost 
minimization, accommodating necessary operational flexibility, and 
promoting allowance market liquidity. All of these purposes are 
advanced by rules that allow sources to trade allowances freely (both 
with other sources and with non-source entities such as brokers). All 
of these purposes are also advanced by rules that allow unused 
allowances to be carried over for possible use in future control 
periods, thereby preserving a value for the unused allowances. However, 
while the EPA considers it generally advantageous to place as few 
restrictions on the trading of allowances as possible,\252\ 
unrestricted banking of allowances has a potentially significant 
disadvantage offsetting its advantages, namely that it allows what 
might otherwise be temporary surpluses of allowances in some individual 
control periods to accumulate into a long-term allowance surplus that 
reduces allowances prices and weakens the trading program's incentives 
to control emissions. With weakened incentives, some operators would be 
more likely to choose not to continuously operate and optimize their 
emissions controls, imperiling the ongoing achievement of emissions 
rate performance consistent with the control strategies defined as 
eliminating significant contribution to nonattainment and interference 
with maintenance.
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    \252\ The advantages of trading programs discussed earlier in 
this section--providing continuous emissions reduction incentives, 
facilitating compliance cost minimization, and supporting 
operational flexibility--depend on the existence of a marketplace 
for purchasing and selling allowances, and broader marketplaces 
generally provide greater market liquidity and therefore make 
trading programs better at providing these advantages. The EPA 
recognizes that unrestricted use of net purchased allowances--
meaning quantities of purchased allowances that exceed the 
quantities of allowances sold--by a source or group of sources as an 
alternative to making emissions reductions can interfere with the 
achievement of the desired environmental outcome, and Section 
VII.B.1.c of this proposed rule discusses the enhancements to the 
Group 3 trading program that the EPA is proposing in this rulemaking 
to reduce reliance on net purchased allowances by incentivizing or 
requiring better environmental performance at individual EGUs. 
However, the concern arises from the use of an excessive quantity of 
net purchased allowances for a particular purpose, not from the 
existence of a marketplace where allowances may be freely bought and 
sold.
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    As discussed in detail in Section VII.B.6 of this proposed rule, 
the EPA is proposing to revise the Group 3 trading program by adding 
provisions that would establish a routine recalibration process for 
banked allowances that would be carried out in August 2024 and each 
subsequent August, after the compliance deadline for the control period 
in the previous year. In each recalibration, the EPA would reset the 
total quantity of banked allowances for the Group 3 trading program 
(``Group 3 allowances'') held in all Allowance Management System 
accounts to a target level of 10.5 percent of the sum of the state 
emissions budgets for the current control period. The procedure would 
entail identifying the ratio of the target bank amount to the total 
quantity of banked allowances held in all accounts before the 
conversion and then, if the ratio was less than 1.0, multiplying the 
quantity of banked allowances held in each account by the ratio to 
identify the appropriate recalibrated amount for the account (rounded 
to the nearest allowance), and deducting any allowances in the account 
exceeding the recalibrated amount.
    The EPA believes this revision to the Group 3 trading program's 
banking provisions would complement the proposed revisions to the 
budget-setting process by ensuring that the annual bank recalibration 
would prevent any surplus of allowances created in one control period 
from diminishing the intended stringency and resulting emissions 
reductions of the emissions budgets for subsequent control 
periods.\253\
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    \253\ The EPA recognizes there will be a data lag inherent in 
the future year emissions budgets, because the budgets would reflect 
fleet composition and utilization data reported for a previous 
control period. This means that the budgets for some individual 
control periods may fail to fully keep pace with the EGU fleet's 
trends toward more efficient and cleaner resources. Nonetheless, the 
new approach is a substantial improvement in environmental 
performance of the program compared to a more unlimited approach to 
allowance banking.
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    The calibration procedure would not erase the value of unused 
allowances for the holder, because the larger the quantity of banked 
allowances that is held in a given account before each recalibration, 
the larger the quantity of banked allowances that would be left in the 
account after the recalibration for possible sale or use in meeting 
future compliance requirements. Because the banked allowances would 
always have value, the opportunity to bank allowances would continue to 
advance the purposes served by otherwise unrestricted banking as 
described above. Opportunities to bank unused allowances can serve all 
these same purposes whether a banked allowance is of partial value (if 
the bank needs recalibrating to its target level) or is of full value 
compared to a newly issued allowance for the next control period.
    The proposal to routinely recalibrate the allowance bank is 
discussed further in Section VII.B.6 of this proposed rule.
d. Enhancements To Improve Emissions Performance at Individual Units
    The second set of concerns about the structure of the current CSAPR 
trading programs relates to the general absence of source- or unit-
specific emissions reduction requirements. Without such requirements, 
the programs affect individual sources' emissions

[[Page 20110]]

performance only to the extent that the incentives created by allowance 
prices are high enough relative to the costs of the sources' various 
emissions control opportunities. In circumstances where the incentives 
to control emissions are insufficient, some individual sources even 
idle existing emissions controls. Emissions from these individual 
sources can contribute to increased pollution concentrations downwind 
on the particular days that matter for downwind exceedances of the 
relevant air quality standard and also have the potential to cause 
disproportionate adverse impacts on downwind overburdened communities.
    This EPA intends that the trading program enhancements described in 
Section VII.B.1.b of this proposed rule would improve the Group 3 
trading program's ability to sustain emissions control incentives over 
time such that needed emissions performance would be achieved by all 
participating units without the need for additional requirements to be 
imposed at the level of individual units. However, because obtaining 
needed emissions performance at individual units is also important, the 
EPA proposes to supplement the previously discussed enhancements with 
two other new sets of provisions that would apply to certain individual 
units within the larger context of the Group 3 trading program. The 
allowance price would continue to be the most important driver of good 
environmental performance for most units, but the proposed unit-level 
requirements would be important supplemental drivers of performance and 
would offer additional assurance that significant contribution is 
eliminated on a daily basis during the ozone season by continuous 
operation of existing pollution controls.
i. Unit-Specific Backstop Daily Emissions Rates
    The first of the proposed trading program enhancements intended to 
improve emissions performance at the level of individual units is the 
addition of backstop daily NOX emissions rate provisions 
that would apply to large coal-fired EGUs, defined for this purpose as 
units serving electricity generators with nameplate capacities equal to 
or greater than 100 MW and combusting any coal during the control 
period in question. Starting with the 2024 control period, a 3-for-1 
allowance surrender ratio (instead of the usual 1-for-1 surrender 
ratio) would apply to emissions during the ozone season from any large 
coal-fired EGU with existing SCR controls exceeding a daily average 
NOX emissions rate of 0.14 lb/mmBtu. The additional 
allowance surrender requirement would be integrated into the trading 
program as a new component in the calculation of each unit's primary 
emissions limitation, such that the additional allowances would have to 
be surrendered by the same compliance deadline of June 1 after each 
control period. The amount of additional allowances to be surrendered 
would be determined by computing, for each day of the control period, 
any excess of the unit's reported emissions (in pounds) over the 
emissions that would have resulted from combusting that day's actual 
heat input at an average daily emissions rate of 0.14 lb/mmBtu, summing 
the daily amounts, converting from pounds to tons, and multiplying by 
two. Starting with the 2027 control period, the 3-for-1 surrender ratio 
would apply in the same way to all large coal-fired EGUs, consistent 
with EPA's proposed determinations, first, that a control stringency 
reflecting installation and operation of SCR controls on all large 
coal-fired EGUs is appropriate to address states' good neighbor 
obligations with respect to the 2015 ozone NAAQS, and second, that such 
controls could reasonably be installed by the 2026 control period.
    In prior rules addressing interstate transport of air pollution, 
stakeholders have noted that while seasonal cap-and-trade programs are 
effective at lowering ozone and ozone-forming precursors across the 
ozone season, attainment of the standard is measured on key days and 
therefore it is necessary to ensure that the rule requires emissions 
reductions not just seasonally, but also on those key days.\254\ They 
have noted that while the trading programs established under the 
NOX SIP Call, CAIR, and CSAPR have all been successful in 
ensuring seasonal reductions, states must remain below daily peak 
levels, not just seasonal levels, to reach attainment. These downwind 
stakeholder communities have suggested that operating pollution 
controls on the highest ozone days (and immediately preceding days) 
during the ozone season is of critical importance. The EPA has analyzed 
hourly emissions data reported in prior cap-and-trade programs and has 
identified instances of sources that did not operate SCR controls for 
substantial portions of recent ozone seasons. These instances are 
discussed below and in the EGU NOX Mitigation Strategies 
Proposed Rule TSD in the docket. While the EPA has in prior ozone 
transport actions not found sufficient evidence of emissions control 
idling or non-operation to take the step of building in enhancements to 
the trading program to ensure unit-level control operation, our review 
of that information applied to this context suggests this problem could 
become more prevalent in future years relevant to this action. Rather 
than allow for the potential of continued deterioration in the 
environmental performance of our trading programs, the EPA finds the 
evidence of declining SCR performance in later years of trading 
programs sufficient to justify prophylactic measures in this proposal 
to ensure the emissions control strategy selected at Step 3 is indeed 
implemented at Step 4. Thus, particularly in the context of the more 
stringent 2015 ozone NAAQS combined with the full remedy nature of this 
action and the extended timeframe for which upwind contribution to 
downwind nonattainment is projected to persist, the EPA agrees with 
these stakeholders that the set of measures promulgated in this 
rulemaking to implement the control stringency levels found necessary 
to address states' good neighbor obligations should include measures 
designed to more effectively ensure that individual units operate their 
emission controls routinely throughout the ozone season, thereby also 
ensuring that the controls are planned to be in operation on the 
particular days that turn out to be most critical for ozone formation 
and for attainment of the NAAQS.\255\ Routine operation of emissions 
controls will also provide relief to overburdened communities downwind 
of any units that might otherwise have chosen not to operate their 
controls. In the Ozone Transport TSD, the EPA conducted a screening 
analysis that found nearly all of the EGUs included in this analysis 
are located within a 24-hour transport distance of many areas with 
potential EJ concerns. The EPA is proposing to adopt backstop daily 
rate limits at the individual unit level for this purpose, implemented 
in the context of a trading program (i.e., through enhanced allowance 
surrender ratios), as an alternative to adopting enforceable rate 
limits.
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    \254\ EPA-HQ-OAR-2020-0272. Comment submitted by Ben Grumbles, 
Secretary, Maryland Department of the Environment (MDE).
    \255\ The CSAPR Update was a partial remedy and the Revised 
CSAPR Update addressed downwind nonattainment and maintenance issues 
that were projected to be resolved within a 4 year window. In 
contrast, this rule reflects a full remedy and is addressing 
downwind nonattainment and maintenance issues that are projected to 
persist for more than a decade.
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    The purpose of establishing a backstop daily NOX 
emissions rate and implementing it through additional

[[Page 20111]]

allowance surrender requirements instead of as an enforceable rate 
limit is to incentivize improved emissions performance at the 
individual unit level while continuing to preserve, to the extent 
possible, the advantages that the flexibility of a trading program 
brings to the electric power sector. As discussed in Section VII.B.7 of 
this proposed rule, under existing trading programs without the 
enhancements proposed in this rulemaking, some individual coal-fired 
units with SCR controls have chosen to operate the controls at lower 
removal efficiencies than in past ozone seasons or even to idle the 
controls for entire ozone seasons. In addition, some SCR-equipped units 
have chosen to routinely cycle their emissions controls off at lower 
load levels, such as while operating overnight, instead of operating 
the controls, upgrading the units to enable the controls to be operated 
under those conditions, or not operating the units under those 
conditions.
    The EPA has identified sources of interstate ozone pollution such 
as the New Madrid and Conemaugh plants (in Missouri and Pennsylvania, 
respectively) whose SCR controls were not operating for substantial 
portions of recent ozone seasons. The data in Figures 1 and 2 to 
Section VII.B.1.c.i, included in Appendix G of the Ozone Transport 
Policy Analysis Proposed Rule TSD available in the docket for this 
rulemaking, demonstrate that these units have operated their SCRs 
better and more consistently during years with higher NOX 
allowance prices. Downwind stakeholders have noted that some of the 
higher emission rates (specifically in the case of Conemaugh Unit 2 in 
2019) have occurred on the day of and the preceding day of an ozone 
exceedance in bordering states.\256\
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    \256\ EPA-HQ-OAR-2020-0272-0094.
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    The EPA believes that the design of the proposed daily emissions 
rate provisions would be effective in addressing these types of high-
emitting behavior by significantly raising the cost of planned operator 
decisions that substantially compromise environmental performance. At 
the same time, the provision would not unduly penalize an occasional 
unplanned exceedance, because the amount of additional allowances that 
would have to be surrendered to address a single day's exceedance would 
be much smaller than the amount that would have to be surrendered to 
address planned poor performance sustained over longer time 
periods.\257\
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    \257\ While the proposed design of the daily emissions rate 
provision would not deter another theoretical type of poor emissions 
control behavior--i.e., turning off emissions controls at times of 
peak electricity demand in order to sell the additional electricity 
that otherwise would have been used to run the control equipment--
EPA's analysis of hourly emissions data does not show that this 
behavior is actually occurring. The data actually suggest the 
opposite--that emissions controls are generally operated better on 
peak demand days than on other days. See the Ozone Policy Analysis 
Proposed Rule TSD for additional details about the assessment of the 
tons and the Discussion of Short-term Emissions Limit document for 
an assessment of control operation on peak demand days.
---------------------------------------------------------------------------

    The EPA proposes to apply the daily emissions rate provisions to 
large coal-fired EGUs, and not to other types of units, for reasons 
that are consistent with EPA's determinations regarding the appropriate 
control stringency for EGUs to address states' good neighbor 
obligations with respect to the 2015 ozone NAAQS. Installation and 
operation of SCR controls is well-established as best practice for 
control of NOX emissions from coal-fired EGUs, as evidenced 
by the fact that the technology is already installed on more than 60 
percent of the sector's total coal-fired capacity. In the context of 
the need for states to address their good neighbor obligations with 
respect to the 2015 ozone NAAQS, the EPA is proposing to determine that 
a control stringency reflecting universal installation and operation of 
SCR technology at large coal-fired EGUs is appropriate, based on a 
multi-factor test that includes consideration of cost-effectiveness 
along with air quality factors. Finally, where SCR controls are 
installed, optimized operation of those controls is an extremely cost-
effective method of achieving NOX emissions reductions. The 
EPA believes these considerations support establishment of the proposed 
daily emissions rate provisions on a universal basis for large coal-
fired EGUs, with near-term application of the provisions for units that 
already have the controls installed and deferred application for other 
units, as discussed later.
    With regard to gas-fired steam EGUs, SCR controls are nowhere near 
as prevalent, and while the EPA is proposing to include some SCR 
controls at gas-fired steam units in the selected control stringency, 
the EPA is not proposing to include universal SCR controls at gas-fired 
steam units. Because the EPA does not propose to determine that 
universal installation and operation of SCR controls at gas-fired steam 
EGUs is part of the selected control stringency, in order not to 
constrain the power sector's flexibility to choose which particular 
gas-fired steam EGUs are the preferred candidates for achieving the 
required emissions reductions, the EPA is not proposing to apply the 
daily emissions rate provisions to large gas-fired steam EGUs. Focusing 
the backstop daily emissions rates on coal-fired units is also 
consistent with stakeholder input which has emphasized the need for 
short-term rate limits at coal units given their relatively higher 
emissions rates.
    The EPA developed the proposed level of the daily average 
NOX emissions rate--0.14 lb/mmBtu--through analysis of 
historical data, as described in Section VII.B.7 of this proposed rule. 
A rate of 0.14 lb/mmBtu represents the daily average NOX 
emissions rate that has been demonstrated to be achievable on 
approximately 95 percent of days covering more than 99 percent of total 
ozone-season NOX emissions by coal-fired units with SCR 
controls that are achieving a seasonal NOX average emissions 
rate of 0.08 lb/mmBtu (or less), which is the seasonal NOX 
emissions rate that the EPA has determined is indicative of optimized 
SCR performance by units with existing SCR controls.
    As noted previously, the daily average emissions rate provisions 
are proposed to apply beginning in the 2024 control period for large 
coal-fired units with installed SCR controls, one control period later 
than optimization of those controls would be reflected in the state 
emissions budgets under the proposal. Likewise, the daily average 
emissions rate provisions are proposed to apply beginning in the 2027 
control period for other large coal-fired units, one control period 
later than emissions reductions consistent with the installation and 
operation of SCR controls for such units would be reflected in the 
state emissions budgets under the proposal. With respect to the units 
with existing SCR controls, not applying the daily average rate 
provisions until 2024 would serve two purposes. First, it would provide 
all the units with a preparatory interval to focus attention on 
improving not only the average performance of their SCR controls but 
also the day-to-day consistency of performance before they would be 
held to increased allowance-surrender consequences for exceeding the 
daily rate. Second, it would provide the subset of units that exhaust 
to common stacks with other units that currently lack SCR controls an 
opportunity to exercise the option to install and certify any 
additional monitoring systems needed to monitor the individual units' 
NOX emissions rates separately; otherwise, the daily 
emissions rate provisions would apply to the SCR-equipped units based 
on the combined

[[Page 20112]]

NOX emissions rates measured in the common stacks.\258\
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    \258\ Based on the information reported by sources to the EPA in 
their monitoring plans under 40 CFR part 75, five plants subject to 
this proposal have SCR-equipped and non-SCR-equipped coal-fired EGUs 
that exhaust together to common stacks: The Clifty Creek plant in 
Indiana; the Cooper, Ghent, and Shawnee plants in Kentucky; and the 
Sammis plant in Ohio.
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    With respect to the units without existing SCR controls, not 
applying the daily average emissions rate provisions until 2027 would 
also serve two purposes. First, it would provide a window for plant 
personnel to gain experience operating any new SCR controls, and 
second, it would provide some timing flexibility for any individual 
unit operators who fail to complete SCR control installations before 
the start of the 2026 control period. With respect to both sets of 
units, the EPA believes that the lag in applicability of one control 
period is permissible because the emissions budget provisions are the 
principal provisions intended to drive the emissions reductions 
required under the proposal, while the daily average emissions rate 
provisions are included only to backstop those provisions.
    The EPA believes that the proposed unit-specific daily emissions 
rate provisions would strengthen the incentives for individual coal-
fired units with SCR controls to operate and optimize performance of 
the controls. Continuous operation and optimization of post-combustion 
controls at individual units would help address individual days that 
prove in real time to be most critical for downwind ozone levels. 
Better continuous emissions performance by individual units would also 
help address disparate impacts of pollution on overburdened communities 
downwind from the units.
    The proposed unit-specific target daily emissions rates are 
discussed further in Section VII.B.7 of this proposed rule.
ii. Unit-Specific Emissions Limitations Contingent on Assurance Level 
Exceedances
    The second of the proposed trading program enhancements intended to 
improve emissions performance at the level of individual units is the 
addition of unit-specific secondary emissions limitations. The 
secondary emissions limitations would be determined on a unit-specific 
basis according to each unit's individual performance but would apply 
to a given unit only under the circumstance where a state's assurance 
level for a control period has been exceeded, the unit is included in a 
group of units to which responsibility for the exceedance has been 
apportioned under the program's assurance provisions, and the unit 
operated during at least 10% of the hours in the control period. Where 
these conditions for application of a secondary emissions limitation to 
a given unit for a given control period are met, the unit's secondary 
emissions limitation would consist of a prohibition on NOX 
emissions during the control period that exceed by more than 50 tons 
the NOX emissions that would have resulted if the unit had 
achieved an average emissions rate for the control period equal to the 
higher of 0.10 lb/mmBtu or 125 percent of the unit's lowest average 
emissions rate for any previous control period under any CSAPR seasonal 
NOX trading program during which the unit operated for at 
least 10 percent of the hours.
    The proposed secondary emissions limitation would be in addition 
to, not in lieu of, the primary emissions limitation applicable to each 
source, which would continue to take the form of a requirement to 
surrender a quantity of allowances based on the source's emissions, and 
also in addition to the existing assurance provisions, which similarly 
would continue to take the form of a requirement for the owners and 
operators of some sources to surrender additional allowances when a 
state's assurance level is exceeded. In contrast to these other 
requirements, the proposed unit-specific secondary emissions limitation 
would take the form of a prohibition on emissions over a specified 
level, such that any emissions by a unit exceeding its secondary 
emissions limitation would be subject to potential administrative or 
judicial action and subject to penalties and other forms of relief 
under the CAA's enforcement authorities. The reason for proposing this 
form of limitation is that experience under the existing CSAPR trading 
programs has shown that, in some circumstances, the existing assurance 
provisions have been insufficient to prevent exceedances of a state's 
assurance level for a control period even when the likelihood of an 
exceedance has been foreseeable and the exceedance could have been 
readily avoided if certain units had operated with emissions rates 
closer to the lower emissions rates achieved in past control periods. 
The assurance levels exist to ensure that emissions from each state 
that contribute significantly to nonattainment or interfere with 
maintenance of a NAAQS in another state are prohibited. North Carolina 
v. EPA, 531 F.3d 896, 906-908 (D.C. Cir. 2008). EPA's programs to 
eliminate significant contribution must therefore achieve this 
prohibition, and the new evidence of exceedances of the assurance 
provisions demonstrate that EPA's existing approach may not be 
sufficient to accomplish this statutory mandate.
    The purpose of including assurance levels higher than the state 
emissions budgets in the CSAPR trading programs is to provide 
flexibility to accommodate operational variability attributable to 
factors that are largely outside of an individual owner's or operator's 
control, not to allow owners and operators to plan to emit at emissions 
rates that could be anticipated to cause a state's total emissions to 
exceed the state's emissions budget or assurance level. Conduct leading 
to a foreseeable, readily avoidable exceedance of a state's assurance 
level cannot be reconciled with the statutory mandate of the CAA's good 
neighbor provision that emissions ``within the state'' significantly 
contributing to nonattainment or interfering with maintenance of a 
NAAQS in another state must be prohibited. Because the current CSAPR 
regulations do not expressly prohibit such conduct and have proven 
insufficient to deter it in some circumstances, the EPA is proposing to 
correct the regulatory deficiency in the Group 3 trading program by 
adding secondary emissions limitations that cannot be complied with 
through the use of allowances.
    The EPA notes that although the principal purpose of the proposed 
secondary emissions limitations is to strengthen the assurance 
provisions, which apply on a statewide, seasonal basis, the unit-
specific structure of the new limitations would strengthen the 
incentives for individual units to maintain their emissions performance 
at levels consistent with their previously demonstrated capabilities. 
For units with existing post-combustion emissions controls, the new 
limitations would strengthen the incentives to operate and optimize the 
controls continuously, and for units without such existing controls, 
the new limitations would strengthen the incentives to minimize 
NOX emissions rates through other possible measures such as 
improved maintenance and optimization of combustion parameters. 
Continuous operation of post-combustion controls and greater attention 
to the combustion process at individual units can be expected to reduce 
some individual units' emissions rates throughout the ozone season, 
including on the days that turn out to be most critical for downwind 
ozone

[[Page 20113]]

levels. Better emissions performance on average across the ozone season 
by individual units would also help address disparate impacts of 
pollution on overburdened communities downwind from some such units.
    The proposed unit-specific secondary emissions limitations are 
discussed further in Section VII.B.8 of this proposed rule.
2. Expansion of Geographic Scope
    As part of the proposed approach for implementing the 
NOX emissions reductions from EGUs identified as necessary 
to address various states' obligations under the good neighbor 
provision with respect to the 2015 ozone NAAQS, the EPA is proposing to 
expand the existing geographic scope of the existing CSAPR 
NOX Ozone Season Group 3 Trading Program to encompass the 
additional states (and Indian country within the borders of such 
states) found to have such obligations with respect to EGUs. 
Specifically, the EPA is proposing to expand the Group 3 trading 
program to include the following states and Indian country within the 
borders of the states: Alabama, Arkansas, Delaware, Minnesota, 
Mississippi, Missouri, Nevada, Oklahoma, Tennessee, Texas, Utah, 
Wisconsin, and Wyoming. Any unit located in a newly added jurisdiction 
that meets the existing applicability criteria for the Group 3 trading 
program would become an affected unit under the program, as discussed 
in Section VII.B.3 of this proposed rule.
    CSAPR, the CSAPR Update, and the Revised CSAPR Update also applied 
to sources in Indian country, although, when those rules were issued, 
no existing EGUs within the regions covered by the rules were located 
on lands that the EPA understood at the time to be Indian country.\259\ 
In contrast, within the proposed geographic scope of this rulemaking, 
the EPA is aware of areas of Indian country within the borders of both 
Utah and Oklahoma with existing EGUs that would meet the program's 
applicability criteria. Issues related to state, tribal, and federal 
jurisdiction with respect to sources in Indian country in general and 
in these areas in particular are discussed in Section IV.C.2 of this 
proposed rule. EPA's proposed approach for determining a portion of 
each state's budget for each control period that would be set aside for 
allocation to any units in areas of Indian country within the state not 
subject to the state's CAA implementation planning authority is 
discussed in Section VII.B.9 of this proposed rule.
---------------------------------------------------------------------------

    \259\ CSAPR and the CSAPR Update both applied to EGUs located in 
areas within Oklahoma's borders that are now understood to be Indian 
country, consistent with the U.S. Supreme Court's decision in McGirt 
v. Oklahoma, 140 S. Ct. 2452 (2020) (and subsequent case law), 
clarifying the extent of certain Indian country within Oklahoma's 
borders. However, those rules were issued before the McGirt 
decision. See Section IV.C.2.a.
---------------------------------------------------------------------------

    Units in each state would join the Group 3 trading program on one 
of two possible dates during the program's 2023 control period (that 
is, the period from May 1, 2023, through September 30, 2023). The 
reason that two entry dates are possible is that, as discussed in 
Section VII.B.11 of this proposed rule, the effective date of a final 
rule in this rulemaking may fall after May 1, 2023. In the case of 
states (and Indian country within the states' borders) whose sources do 
not currently participate in the CSAPR NOX Ozone Season 
Group 2 trading program--Delaware, Minnesota, Nevada, Utah, and 
Wyoming--EPA proposes that the sources would begin participating in the 
Group 3 trading program on the later of May 1, 2023, or the final 
rule's effective date. However, in the case of the states (and Indian 
country within the states' borders) whose sources do currently 
participate in the Group 2 trading program--Alabama, Arkansas, 
Mississippi, Missouri, Oklahoma, Tennessee, Texas, and Wisconsin--EPA 
proposes that the sources would begin participating in the Group 3 
trading program on May 1, 2023, regardless of the final rule's 
effective date, subject to transitional provisions designed to ensure 
that the increased stringency of the Group 3 trading program as revised 
in this rulemaking would not substantively affect the sources' 
requirements prior to the rule's effective date. This approach provides 
a simpler transition for the sources currently covered by the Group 2 
trading program than the alternative approach of being required to 
switch from the Group 2 trading program to the Group 3 trading program 
in the middle of a control period, and it is the same approach that was 
followed for sources that transitioned from the Group 2 trading program 
to the Group 3 trading program in 2021 under the Revised CSAPR Update. 
Section VII.B.11 of this proposed rule contains further discussion of 
the rationale for this approach and the specific proposed transitional 
provisions.
    The EPA notes that under the proposed rule, the expanded Group 3 
trading program would include not only the 22 states for which the EPA 
is proposing to determine that the required control stringency 
includes, among other measures, installation of new post-combustion 
controls, but also the three states--Alabama, Delaware, and Tennessee--
for which the EPA is proposing to determine that the required control 
stringency does not include such measures. In previous rulemakings, the 
EPA has chosen to combine states in a single multi-state trading 
program only where the selected control stringencies were comparable, 
in order to ensure that states did not effectively shift their 
emissions reduction requirements to other states with less stringent 
emissions reduction requirements by using net out-of-state purchased 
allowances. Although the assurance provisions in the CSAPR trading 
programs were designed to address the same general concern about 
excessive shifting of emissions reduction activities between states, 
EPA chose not to rely on the assurance provisions as sufficient to 
allow for interstate trading in situations where the states were 
assigned differing emissions control stringencies.
    In this rulemaking, the EPA believes the previous concern about the 
possibility that certain states might not make the required emissions 
reductions is sufficiently addressed through the various proposed 
enhancements to the design of the trading program, even where states 
have been assigned differing emissions control stringencies. First, the 
existing assurance provisions would be substantially strengthened 
through the addition of the unit-specific secondary emissions 
limitations discussed in Sections VII.B.1.c.ii and VII.B.8 of this 
proposed rule. Second, by ensuring that individual units operate their 
emissions controls effectively, the unit-specific backstop daily 
emissions rate provisions discussed in Sections VII.B.1.c.i and VII.B.7 
of this proposed rule would necessarily also ensure that required 
emissions reductions occur within the state. With these enhancements to 
the design of the trading program, the EPA does not believe it would be 
necessary for sources in Alabama, Delaware, and Tennessee to be 
excluded from the revised Group 3 trading program simply because their 
emissions budgets would reflect a different selected emissions control 
stringency than the other states in the program.
    The EPA requests comment on the proposed expansion of the 
geographic scope of the Group 3 trading program to include the states 
and areas of Indian country identified above. The EPA also requests 
comment on the proposed timing under which the two sets of states and 
Indian country within the

[[Page 20114]]

respective states' borders would be added to the program.
3. Applicability and Tentative Identification of Newly Affected Units
    The Group 3 trading program generally applies to any stationary, 
fossil-fuel-fired boiler or stationary, fossil fuel-fired combustion 
turbine located in a covered state (or Indian country within the 
borders of a covered state) and serving at any time on or after January 
1, 2005, a generator with nameplate capacity exceeding 25 MW and 
producing electricity for sale, with exemptions for certain 
cogeneration units and certain solid waste incineration units. To 
qualify for an exemption as a cogeneration unit, an otherwise-affected 
unit generally (1) must be designed to produce electricity and useful 
thermal energy through the sequential use of energy, (2) must convert 
energy inputs to energy outputs with efficiency exceeding specified 
minimum levels, and (3) may not produce electricity for sale in amounts 
above specified thresholds. To qualify for an exemption as a solid 
waste incineration unit, an otherwise-affected unit generally (1) must 
meet the CAA section 129(g)(1) definition of a ``solid waste 
incineration unit'' and (2) may not consume fossil fuel in amounts 
above specified thresholds. The complete text of the Group 3 trading 
program's applicability provisions and the associated definitions can 
be found at 40 CFR 97.1004 and 97.1002, respectively.
    The EPA is not proposing in this rulemaking to revise the existing 
applicability provisions for the Group 3 trading program. Thus, any 
unit that is located in a newly added state and that meets the existing 
applicability criteria for the Group 3 trading program would become an 
affected unit under the program. The fact that the applicability 
criteria for all of the CSAPR trading programs are identical therefore 
is sufficient to establish that any units that are currently required 
to participate in another CSAPR trading program in any of the proposed 
additional states where such other programs currently are in effect--
Alabama, Arkansas, Minnesota, Mississippi, Missouri, Oklahoma, 
Tennessee, Texas, and Wisconsin (including Indian country within the 
borders of such states)--would also become subject to the Group 3 
trading program.
    In the proposed additional states where other CSAPR trading 
programs are not currently in effect--Delaware, Nevada, Utah, and 
Wyoming (including Indian country within the borders of such states)--
units already subject to the Acid Rain Program generally would also 
meet the applicability criteria for the Group 3 trading program, 
especially if the units are not capable of producing both electricity 
and useful thermal energy. Based on a preliminary screening analysis of 
the units in these states that currently report emissions and operating 
data to the EPA under the Acid Rain Program and that do not report the 
capability to produce both electricity and useful thermal energy, the 
Agency believes that all such units are likely to meet the 
applicability criteria for the Group 3 trading program.
    Because the applicability criteria for the Acid Rain Program and 
the Group 3 trading program are not identical, it is possible that some 
units could meet the applicability criteria for one program but not the 
other. Using data reported to the U.S. Energy Information 
Administration, the EPA has identified 10 sources in Delaware, Nevada, 
Utah, and Wyoming (and Indian country within the borders of the states) 
with 27 units that appear to meet the general applicability criteria 
for the Group 3 trading program and that either (1) do not currently 
report NOX emissions and operating data to the EPA under the 
Acid Rain Program or (2) currently report NOX emissions and 
operating data to the EPA under the Acid Rain Program and also report 
the capability to produce both electricity and useful thermal energy. 
These units are listed in Table VII.B.3-1 of this proposed rule. For 
each of these units, the table shows the estimated historical heat 
input and emissions data that the EPA proposes to use for the unit when 
determining state emissions budgets if the unit is ultimately treated 
as subject to the Group 3 trading program.\260\ The EPA currently lacks 
sufficient information to determine whether any of the units listed in 
the table meets all of the relevant criteria to qualify for an 
exemption from the Group 3 trading program as a cogeneration unit or a 
solid waste incineration unit.
---------------------------------------------------------------------------

    \260\ As discussed in Section VII.B.10.b of this proposed rule, 
the EPA expects that any unit that becomes subject to the Group 3 
trading program pursuant to a final rule in this rulemaking and that 
does not already report emissions data to the EPA in accordance with 
40 CFR part 75 would not be required to report emissions data or be 
subject to allowance holding requirements under the Group 3 trading 
program until May 1, 2024, because of the minimum time interval 
allowed for installation and certification of the required 
monitoring systems. Such a unit would not be taken into account for 
purposes of determining state emissions budgets and unit-level 
allocations under the Group 3 trading program until the 2024 control 
period. As indicated in the notes to Table VII.B.3-1 of this 
proposed rule, six of the listed units have reported to the Energy 
Information Administration that they plan to retire in 2023.

                                     Table VII.B.3-1--Selected Existing Units That Could Be Affected Under Proposal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                     Estimated
                                                                                                                     Estimated     ozone season
                                                                                                                   ozone season     average NOX
             State                Facility ID     Facility name            Unit ID               Unit type          heat input    emissions rate   Notes
                                                                                                                      (mmBtu)       (lb/mmBtu)
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Delaware......................             591  Christiana.......  11....................  CT...................           1,974          0.2594       1
Delaware......................             591  Christiana.......  14....................  CT...................           1,816          0.2027       1
Delaware......................           52193  Delaware City      DCPP2.................  Boiler...............         872,824          0.0176       2
                                                 Refinery.
Delaware......................           52193  Delaware City      DCPP3.................  Boiler...............       2,380,430          0.0169       2
                                                 Refinery.
Delaware......................           52193  Delaware City      DCPP4.................  Boiler...............       1,374,817          0.0438    2, 3
                                                 Refinery.
Delaware......................           52193  Delaware City      MECCU1................  CT...................       1,679,396          0.0070       2
                                                 Refinery.
Delaware......................           52193  Delaware City      MECCU2................  CT...................       1,679,396          0.0062       2
                                                 Refinery.
Delaware......................            7153  Hay Road.........  1.....................  CT...................       1,354,272          0.0685       1
Delaware......................            7153  Hay Road.........  2.....................  CT...................       1,311,286          0.0663       1
Nevada........................            2322  Clark............  GT4...................  CT...................         190,985          0.0475  ......
Nevada........................            2322  Clark............  GT5...................  CT...................       1,455,741          0.0191  ......
Nevada........................            2322  Clark............  GT6...................  CT...................       1,455,741          0.0187  ......
Nevada........................            2322  Clark............  GT7...................  CT...................       1,455,741          0.0178  ......
Nevada........................            2322  Clark............  GT8...................  CT...................       1,455,741          0.0204  ......
Nevada........................           54350  Nev. Cogen.        GTA...................  CT...................         660,100          0.0377    2, 4
                                                 Assoc. 1--Garnet
                                                 Val.

[[Page 20115]]

 
Nevada........................           54350  Nev. Cogen.        GTB...................  CT...................         660,100          0.0387    2, 4
                                                 Assoc. 1--Garnet
                                                 Val.
Nevada........................           54350  Nev. Cogen.        GTC...................  CT...................         660,100          0.0387    2, 4
                                                 Assoc. 1--Garnet
                                                 Val.
Nevada........................           54349  Nev. Cogen.        GTA...................  CT...................         749,778          0.0323    2, 4
                                                 Assoc. 2--Black
                                                 Mtn.
Nevada........................           54349  Nev. Cogen.        GTB...................  CT...................         749,778          0.0370    2, 4
                                                 Assoc. 2--Black
                                                 Mtn.
Nevada........................           54349  Nev. Cogen.        GTC...................  CT...................         749,778          0.0364    2, 4
                                                 Assoc. 2--Black
                                                 Mtn.
Nevada........................           56405  Nevada Solar One.  HI....................  Boiler...............         479,452          0.1667  ......
Nevada........................           54271  Saguaro..........  CTG1..................  CT...................       1,383,149          0.0314       2
Nevada........................           54271  Saguaro..........  CTG2..................  CT...................       1,383,149          0.0301       2
Utah..........................           50951  Sunnyside........  1.....................  Boiler...............       1,888,174          0.1715  ......
Wyoming.......................           56312  Shute Creek......  021A..................  CT...................       1,000,050          0.0081       2
Wyoming.......................           56312  Shute Creek......  021B..................  CT...................       1,000,050          0.0093       2
Wyoming.......................           56312  Shute Creek......  021C..................  CT...................       1,000,050          0.0084       2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table notes:
\1\ Unit already reports NOX emissions and heat input data to the EPA under 40 CFR part 75 to comply with SIP requirements.
\2\ Unit reports capability of producing both electricity and useful thermal energy.
\3\ Unit already reports NOX emissions and heat input data to EPA under 40 CFR part 75 for the Acid Rain Program.
\4\ Unit has reported a planned retirement date of March 2023 to the Energy Information Administration.

    The EPA requests comment on which existing units in Delaware, 
Nevada, Utah, and Wyoming and Indian country within the borders of such 
states would or would not meet the applicability criteria for the Group 
3 trading program. In addition, with respect to each of the units 
listed in Table VII.B.3-1 of this proposed rule, the EPA requests 
comment, with supporting data, on whether the unit would or would not 
meet all relevant criteria set forth in 40 CFR 97.1004 and the 
associated definitions in 97.1002 to qualify for an exemption from the 
trading program as a cogeneration unit or a solid waste incineration 
unit (however, see Section VI.B.3 of this proposed rule). The EPA also 
requests comment, with supporting data, on whether the estimated 
historical heat input and emissions data identified for the units in 
Table VII.B.3-1 of this proposed rule are representative for the 
respective units.
4. New and Revised State Emissions Budgets
    The EPA is quantifying budgets or budget formulas specific to each 
year to ensure that EGUs continue to be incentivized to implement the 
full extent of EPA's selected control stringency for future control 
periods. By doing so, the EPA is accounting for both scheduled and not-
yet-scheduled fleet turnover in future years. For instance, if State 
X's budget was 5,000 tons in 2023 but there are 100 tons of emissions 
from a unit scheduled to retire at the end of that year and 50 tons 
expected from a new unit coming online by the following year, then the 
state emissions budget for 2024 will reflect these scheduled changes by 
establishing a budget of 5,000 tons-100 tons + 50 tons = 4,950 tons for 
the subsequent year.
    In the Revised CSAPR Update, the EPA included announced fleet 
changes in state emissions budgets. Several commenters applauded the 
merit of this approach and the importance of establishing emissions 
budgets that were robust to an evolving fleet while noting that ``fleet 
composition is changing constantly and can be exceedingly difficult to 
project'' leading to overstated emissions budgets to the extent that 
future retirements were not announced at the time of rule promulgation. 
Commenters added that ``to address this problem and prevent future 
unknown retirements from exacerbating this issue, the final rule should 
include a provision to make additional adjustments to the 
NOX budgets based on newly discovered fleet changes.'' \261\ 
Commenters were suggesting a dynamic budget approach where the 
mitigation measures and control stringencies that constituted removal 
of significant contribution would be identified in a final rule, but 
the future year state budgets would be dynamic as the EPA applied those 
stringency assumptions to future year fleet composition data as it 
became available. While the stringency (reflected by assumed emissions 
rate for a mitigation technology), would be constant, the fleet 
composition (reflected by unit heat input) is dynamic. Multiplying the 
assumed emissions rate for each unit by the heat input for each unit 
and summing the results to the state level would provide a given year's 
state emissions budget, and thus under this approach the state 
emissions budgets would be dynamic as well.
---------------------------------------------------------------------------

    \261\ EPA-HQ-OAR-2020-0272-0094.
---------------------------------------------------------------------------

    The EPA is proposing a dynamic budget approach in this rule, where 
emissions budgets starting in the 2025 control period and beyond will 
be determined through ministerial actions subsequent to this rule's 
promulgation and based upon the formula described in this rule. This 
rule will determine the mitigation strategies, respective emissions 
rates, and formulas and methodologies to be applied to future year 
data, with which the EPA will perform ministerial actions to calculate 
emissions budgets for control periods in 2025 and each year thereafter. 
(Such actions will be publicly announced through notices of data 
availability (NODAs), similar to how other periodic ministerial actions 
to implement the trading programs are currently handled. And as with 
such other actions, interested parties will have the opportunity to 
seek corrections or administrative adjudication under 40 CFR part 78 if 
they believe any data used in making these calculations, or the 
calculations themselves, are in error.) In this manner, the state 
emissions budgets ultimately implemented for each such future control 
period will be a product of the data and formula promulgated in this

[[Page 20116]]

action applied to future year reported data that is closer to that 
future control period and therefore more representative of the fleet 
for that future control period. As such, the budgets will more 
accurately reflect power sector composition in that future year and 
will therefore better achieve the desired environmental outcome over 
time.
    For instance, 2025 budgets will be identified by May 1, 2024, using 
the latest available reported operational data at that time (2023 heat 
input data and fleet inventory) along with the formulas and emissions 
rates quantified in this rule. Therefore, if a unit retires in early 
2023 but had not announced its upcoming retirement at the time of rule 
finalization, the dynamic budget approach would ensure that the budgets 
for future control periods starting in 2025 would reflect the 
identified control stringency applied to a fleet that reflects that 
retirement. If the EPA took an alternative approach of computing the 
2025 budget with available data at the time final rule analysis was 
being conducted, this retirement would likely not be captured in the 
2025 state emissions budget, which would lead to a budget that did not 
fully reflect the application of the identified control stringency. 
This approach has the advantage of mitigating uncertainty regarding 
future retirements, new builds, and existing fleet operational/dispatch 
changes in response to EGU inventory changes.
    The example below illustrates the effectiveness of the dynamic 
budget. In the preset budget approach for 2026, the 2026 heat input is 
estimated based on the latest available heat input data at the time of 
rule promulgation (e.g., 2021), which cannot reflect a subsequent fleet 
change in heat input values (column 2) due to an unanticipated 
retirement of one of the state's coal-fired units in late 2023. 
However, the dynamic budget would use 2024 heat input values as opposed 
to the 2021 heat input values as the latest representative values to 
inform the 2026 state emissions budget. Therefore, the heat input 
values in column 2 under the dynamic scenario reflect the change in 
fleet composition, and when multiplied by the relevant identified 
control stringency (to be identified when this rule is finalized), the 
corresponding tonnage (15,000 tons) summed in column 4 constitutes a 
state budget that better reflects the identified control stringency 
applied to the fleet composition for that year as opposed to the 17,000 
tons in summed in the first table. As illustrated in the example, the 
dynamic variable is the heat input variable which changes over time to 
reflect the most representative EGU fleet.
[GRAPHIC] [TIFF OMITTED] TP06AP22.001

    The EPA requests comment on this dynamic budget approach, including 
the methodology, the start year, and the impacts.
    With regard to the state emissions budgets for the 2023 and 2024 
control periods promulgated in this rule, the EPA is using the best 
available data at the time of the proposed rule regarding retirements 
and new builds. The EPA relies on a compilation of data from DOE EIA 
Form 860 (where facilities report their future retirement plans) and 
information included in the Agency's NEEDS database. This information 
is considered to be highly reliable, real-world information that 
provides the EPA with high confidence that such retirements will in 
fact occur. EPA plans to update this data on retirements and new builds 
at final rule using the latest information available from these sources 
at that time as well as input provided by commenter.
    EPA's emissions budget methodology and formula for establishing 
Group 3 budgets are described in detail in the Ozone Transport Policy 
Analysis Proposed Rule TSD and summarized below.
a. Methodology for Determining Preset State Emissions Budgets for the 
2023 and 2024 Control Periods
    For determining state emissions budgets, the EPA generally uses 
historical ozone season data from the 2021 ozone season, the most 
recent data and therefore the most representative of near-term fleet 
conditions. This is similar to the approach taken in the CSAPR Update 
where the EPA began with 2015 data (the most recent year at the time). 
As in the CSAPR Update, the EPA combined historical data with IPM data 
to determine emissions budgets as follows:

    (1) Determine a future year baseline--Start with the latest 
reported historical unit-level data (e.g., 2021), and adjust any 
unit data where a retirement, a new build, a coal-to-gas conversion, 
or a SCR retrofit is known to occur by the baseline year. This 
results in a future year (e.g., 2023) baseline for emissions budget 
purposes.
    (2) Factor in additional emissions controls for the selected 
control stringency for the given state in the given year--For the 
unit-level emissions control technologies identified in this control 
stringency, adjust the baseline unit-level emissions and emissions 
rates. For example, if an SCR-controlled coal unit had a baseline 
emissions rate greater than 0.08 lb/mmBtu, its emissions rate and 
corresponding emissions would be adjusted down to levels reflecting 
its operation at 0.08 lb/mmBtu.
    (3) Incorporate generation shifting--Use IPM in a relative way 
to capture the reductions expected from generation shifting 
(constrained to within each state) at the representative dollar per 
ton level corresponding to the selected control stringency.

    By using historical unit and state-level NOX emissions 
rates, heat input, and emissions data in the first stage of budget 
setting process outlined above, the EPA is grounding its budgets in the 
most recent representative historical operation for the covered 
units.\262\ This dataset is a reasonable starting point for

[[Page 20117]]

the budget-setting process as it reflects the latest data reported by 
affected facilities under 40 CFR part 75. The reporting requirements 
include quality control measures, verification measures, and 
instrumentation to best record and report the data. In addition, the 
designated representatives of EGU sources are required to attest to the 
accuracy and completeness of the data. The EPA adjusted the 2021 ozone-
season data to reflect committed fleet changes under a baseline 
scenario (i.e., announced and confirmed retirements, new builds, and 
retrofits that have already occurred). For example, if a unit emitted 
in 2021, but retired in 2022, its 2021 emissions would not be included 
in the 2023 baseline estimate. For units that had no known changes, the 
2023 baseline emissions assumption was the actual reported data from 
2021. The EPA also included known new units and scheduled retrofits in 
this manner. Using this method, the EPA arrived at a baseline emission, 
heat input, and emissions rate estimate for each unit for a future year 
(e.g., 2023), and then was able to aggregate those unit-level estimates 
to state-level totals. These state-level totals constituted the state's 
baseline from an engineering analytics perspective. The ozone-season 
state-level emissions, heat input, and emissions rates for covered 
sources under a baseline scenario were determined for each future year 
examined that receives a preset budget under this proposed rule (2023 
and 2024).
---------------------------------------------------------------------------

    \262\ The EPA notes that historical state-level ozone season EGU 
NOX emissions rates are publicly available and quality 
assured data. They are monitored using CEMS or other methodologies 
allowed for use by qualifying units under 40 CFR part 75 and are 
reported to the EPA directly by power sector sources.
---------------------------------------------------------------------------

    The EPA then examined how the baseline emissions and emissions 
rates would change under different control stringencies for EGUs. For 
instance, under the SCR optimization scenario, if a unit was not 
operating its SCR at 0.08 lb/mmBtu or lower in the baseline, the EPA 
lowered that unit's assumed emissions rate to 0.08 lb/mmBtu and 
calculated the impact on the unit's and state's emissions rate and 
emissions. Note that the heat input is held constant for the unit in 
the process, reflecting the same level of unit operation compared to 
historical 2021 data. An improved emissions rate is then applied to 
this heat input, reflecting control optimization. In this manner, the 
state-level baseline totals reflecting known changes were adjusted to 
reflect the additional application of the assumed control technology at 
a given control stringency.
    Finally, the EPA used IPM to capture any generation shifting at a 
given control stringency necessary for the majority of the respective 
emissions control technology to operate. The EPA explains how it 
accounts for generation shifting in more detail in Section VI.B of this 
proposed rule and in the Ozone Transport Policy Analysis Proposed Rule 
TSD. In this rule, as a proxy for the near-term reductions required in 
2023 and 2024, the EPA has constrained generation shifting to occur 
only within-state. The EPA also estimates emissions reductions 
associated with generation shifting in 2025 and 2026 for purposes of 
the illustrative state budgets, but as explained below, the dynamic 
budget process to determine budgets for those years will incorporate 
emissions reductions attributable to generation shifting through the 
inclusion of newly reported unit-level data from the future compliance 
periods.
b. Methodology for Determining Dynamic State Emissions Budgets for 
Control Periods in 2025 Onwards
    The methodology for determining state emissions budgets for later 
control periods (2025 and beyond) is nearly identical to the process 
for quantifying preset budgets in 2023 and 2024 described earlier; it 
is just applied at a later date and applied to the most recent 
representative operational available at that time. The EPA will issue 
by ministerial action these dynamic budget quantifications 
approximately 1 year before the relevant control period. For instance, 
starting in early 2024, the EPA would take the most recent 2023 ozone 
season data, calculate 2025 state emissions budgets using the 
methodology below and update its unit-level and state-level state 
emissions budget files that will be released when this rule is 
finalized (and for which the EPA has included in this proposed rule 
current examples for public comment). By March 1 of 2024, and each year 
thereafter, the EPA would make publicly available (in manner similar to 
data and preliminary computations for allocations from new unit set-
asides) the preliminary state emissions budgets and unit-level 
allocations for the subsequent control period (e.g., 2025) and would 
provide stakeholders with a 30-day opportunity to submit any objections 
to the updated data and computations. By May 1 of 2024, and each year 
thereafter, the EPA would issue the final budgets and allowance 
allocations for the next control period (e.g., 2025).
    The differences to each of the formula steps to calculate dynamic 
budgets for control periods in 2025 and beyond, relative to the 
calculation of preset budgets for the 2023 and 2024 control periods, 
are described later:

    (1) Determine a future year baseline--At this step, the EPA 
would start with the latest reported historical unit-level heat 
input data available at that time (e.g., for 2025 state emissions 
budgets, the EPA would use the newly available 2023 heat input data 
rather than 2021 heat input data). Doing so would capture the latest 
operational data reflecting new builds and retirements. This would 
yield a future year (e.g., 2025) baseline for emissions budget 
purposes.
    (2) Factor in additional emissions controls for the selected 
control stringency for the given state in the given year--For the 
unit-level emissions reduction measures identified in the selected 
control stringency, adjust the baseline unit-level emissions and 
emissions rates. This step would be nearly the same for control 
periods in 2025 and beyond as for the 2023 and 2024 control periods, 
the only difference being that as described in Section VI.D of this 
proposed rule, for each control period from 2026 onward, the unit-
specific emissions rates assumed for all affected states except 
Alabama, Delaware, and Tennessee will reflect the selected control 
stringency that incorporates post-combustion control retrofit 
opportunities for the relevant units identified in the state 
emissions budgets and calculations appendix to the Ozone Transport 
Policy Analysis Proposed Rule TSD. These rates would be defined in 
this rule and would not change subsequently. They would not be 
applied until 2026, based on the time necessary to install these 
mitigation technologies as discussed in Sections VI.B, VI.C, and 
VII.A of this proposed rule.
    (3) Incorporate generation shifting--This step would be 
automatically captured in dynamic budget calculations as generation 
shifting in a compliance scenario would no longer have to be 
projected by IPM and incorporated into the state budgets through an 
additional calculation. Instead, it would be embodied in the newly 
reported heat input data described above and that is used to 
determine the dynamic budgets.

    Additional details, corresponding data and formulas, and examples 
for the dynamic budget are described in the Ozone Transport Policy 
Analysis Proposed Rule TSD.
c. Proposed and Illustrative State Emissions Budgets
    For each covered state (and Indian country within the state's 
borders), preset budgets are established for the two individual control 
periods 2023 and 2024. For 2025 and beyond, the dynamic budget formula 
promulgated in this proposed rule would be applied to future year data 
to quantify state emissions budgets for those control periods. The 
proposed default procedures for allocating the allowances from each 
state budget among the units in each state (and Indian country within 
the state's borders) are described in Section VII.B.9 of this proposed 
rule. The amounts of the proposed state emissions budgets for the 2023 
and 2024 control periods are shown in Table VII.B.4.c-1. Table 
VII.B.4.c-2 shows illustrative state emissions budgets for

[[Page 20118]]

the 2025 and 2026 control periods derived by applying the identified 
control stringency to the most recent historical data, but these 
budgets are only illustrative because, under the proposal, the 
implemented state emissions budgets for these years will be determined 
at a future date through application of the proposed budget-setting 
methodology to data that reflect the emissions control stringencies 
finalized in the rulemaking combined with the latest available data on 
the composition and utilization of the EGU fleet.

    Table VII.B.4.c-1--Proposed CSAPR NOX Ozone Season Group 3 State
     Emissions Budgets for the 2023 and 2024 Control Periods \a\ \b\
------------------------------------------------------------------------
                                 Proposed emissions   Proposed emissions
                                  budgets for 2023     budgets for 2024
             State                 control period       control period
                                       (tons)               (tons)
------------------------------------------------------------------------
Alabama.......................                6,364                6,306
Arkansas......................                8,889                8,889
Delaware......................                  384                  434
Illinois......................                7,364                7,463
Indiana.......................               11,151                9,391
Kentucky......................               11,640               11,640
Louisiana.....................                9,312                9,312
Maryland......................                1,187                1,187
Michigan......................               10,718               10,718
Minnesota.....................                3,921                3,921
Mississippi...................                5,024                4,400
Missouri......................               11,857               11,857
Nevada........................                2,280                2,372
New Jersey....................                  799                  799
New York......................                3,763                3,763
Ohio..........................                8,369                8,369
Oklahoma......................               10,265                9,573
Pennsylvania..................                8,855                8,855
Tennessee.....................                4,234                4,234
Texas.........................               38,284               38,284
Utah..........................               14,981               15,146
Virginia......................                3,090                2,814
West Virginia.................               12,478               12,478
Wisconsin.....................                5,963                5,057
Wyoming.......................                9,125                8,573
------------------------------------------------------------------------
Table Notes:
\a\ The state emissions budget calculations pertaining to Tables
  VII.B.4.c-1 and VII.B.4.c-2 are described in greater detail in the
  Ozone Transport Policy Analysis Proposed Rule TSD. Budget calculations
  and underlying data are also available in Appendix A of that TSD.
\b\ In the event a final rule in this rulemaking becomes effective after
  May 1, 2023, the emissions budgets and assurance levels for the 2023
  control period would be adjusted under the rule's proposed
  transitional provisions to ensure that the increased stringency of the
  new budgets would apply only after the rule's effective date, even
  though the revised Group 3 trading program would be implemented for
  most sources as of the start of the 2023 ozone season on May 1, 2023.
  The 2023 budget amounts shown in Table VII.B.4.c-1 do not reflect
  these possible adjustments. The transitional provisions are discussed
  in Section VII.B.11 of this proposed rule.


  Table VII.B.4.c-2--Illustrative CSAPR NOX Ozone Season Group 3 State
         Emissions Budgets for the 2025 and 2026 Control Periods
------------------------------------------------------------------------
                                    Illustrative         Illustrative
                                 emissions budgets    emissions budgets
             State                for 2025 control     for 2026 control
                                   period (tons)        period (tons)
------------------------------------------------------------------------
Alabama.......................                6,306                6,306
Arkansas......................                8,889                3,923
Delaware......................                  434                  434
Illinois......................                7,463                6,115
Indiana.......................                8,714                7,791
Kentucky......................               11,134                7,573
Louisiana.....................                9,179                3,752
Maryland......................                1,187                1,189
Michigan......................               10,759                6,114
Minnesota.....................                3,910                2,536
Mississippi...................                4,400                1,914
Missouri......................               10,456                7,246
Nevada........................                2,372                1,211
New Jersey....................                  799                  799
New York......................                3,763                3,238
Ohio..........................                8,369                8,586
Oklahoma......................                9,393                4,275
Pennsylvania..................                8,855                6,819
Tennessee.....................                4,008                4,008

[[Page 20119]]

 
Texas.........................               36,619               21,946
Utah..........................               15,146                2,620
Virginia......................                2,948                2,567
West Virginia.................               12,478               10,597
Wisconsin.....................                4,198                3,473
Wyoming.......................                8,573                4,490
------------------------------------------------------------------------

5. Variability Limits and Assurance Levels
    Like each of the other CSAPR trading programs, the Group 3 trading 
program currently includes assurance provisions designed to limit the 
total emissions from the sources in each state (and Indian country 
within the state's borders) in each control period to an amount close 
to the state's emissions budget for the control period, consistent with 
the good neighbor provision's requirement that required emissions 
reductions must be achieved within the state, while allowing some 
flexibility beyond the emissions budget to accommodate year-to-year 
operational variability beyond sources' reasonable ability to control. 
For each state, the assurance provisions establish an assurance level 
for each control period, defined as the sum of the state's emissions 
budget for the control period plus a variability limit, which under the 
existing Group 3 trading program regulations is 21 percent of the 
relevant state emissions budget. The purpose of the variability limit 
is to account for year-to-year variability in EGU operations, which can 
occur for a variety of reasons including changes in weather patterns, 
changes in electricity demand, and disruptions in electricity supply 
from other units or from the transmission grid. Because of the need to 
account for such variability in operations of each state's EGUs, the 
fact that emissions from the state's EGUs may exceed the state's 
emissions budget for a given control period is not treated as 
inconsistent with satisfaction of the state's good neighbor obligations 
as long as the total emissions from the EGUs remain below the state's 
assurance level. Emissions from a state's EGUs above the state's 
emissions budget but below the state's assurance level are treated in 
the same manner as emissions below the state's emissions budget in that 
such emissions are subject to the same requirement to surrender 
allowances at a ratio of one allowance per ton of emissions. In 
contrast, emissions above the state's assurance level for a given 
control period are strongly discouraged as inconsistent with the 
state's good neighbor obligations and are subject to an overall 3-for-1 
allowance surrender ratio. The establishment of assurance levels with 
associated extra allowance surrender requirements was intended to 
respond to the D.C. Circuit's holding in North Carolina requiring the 
EPA to ensure within the context of an interstate trading program that 
sources in each state are required to address their good neighbor 
obligations within the state and may not simply shift those obligations 
to other states by failing to reduce their own emissions and instead 
surrendering surplus allowances purchased from sources in other 
states.\263\
---------------------------------------------------------------------------

    \263\ 531 F.3d at 908.
---------------------------------------------------------------------------

    In this rulemaking, the EPA is not proposing to alter the basic 
structure of the Group 3 trading program's assurance provisions, which 
would continue to set an assurance level for each control period equal 
to the state's emissions budget for the control period plus a 
variability limit and would continue to apply a 3-for-1 surrender ratio 
to emissions exceeding the state's assurance level.\264\ Each assurance 
level also would continue to apply to the collective emissions of all 
units within the state and Indian country within the state's 
borders.\265\ For the 2023 and 2024 control periods, the EPA proposes 
to retain the Revised CSAPR Update's methodology for determining each 
state's variability limit as 21 percent of the state's emissions budget 
for the control period, except that because the EPA is proposing to 
revise the state emissions budgets for these control periods, the EPA 
proposes to determine the corresponding variability limits as 21 
percent of the revised budgets. However, for control periods after 
2024, the EPA is proposing a change to the methodology for determining 
the variability limits. Specifically, the EPA proposes to determine 
each state's variability limit for the control periods in 2025 or a 
later year so that, instead of always multiplying the state's emissions 
budget for the control period by a value of 21 percent, the percentage 
value used would be the higher of 21 percent or the percentage (if any) 
by which the total reported heat input of the state's affected EGUs in 
the control period exceeds the total reported heat input of the state's 
affected EGUs as reflected in the state's emissions budget for the 
control period. For example, if the total reported heat input of the 
state's covered sources for the 2025 control period was 90 percent or 
110 percent of the total reported heat input of the state's covered 
sources for the 2023 control period (i.e., the heat input the EPA would 
have used in computing the state's 2025 emissions budget), then the 
state's variability limit for the 2025 control period would be 21 
percent of the state's emissions budget, while if the total reported 
heat input of the state's covered sources for the 2025 control period 
was 130 percent of the total reported heat input of the state's covered 
sources for the 2023 control period, then the state's variability limit 
for the 2025 control period would be 30 percent of the state's 
emissions budget. The EPA expects that the minimum 21 percent would 
apply in almost all instances, and that the alternative, higher 
percentage value would apply only in control periods where operational 
variability caused an extreme increase relative to the earlier year 
used in setting the state's emissions budget, which would be a 
situation

[[Page 20120]]

meriting a temporarily higher variability limit and assurance level.
---------------------------------------------------------------------------

    \264\ As discussed in Section VII.B.8 of this proposed rule, the 
EPA is also proposing to establish a new secondary emissions 
limitation for individual units that would apply in situations where 
an exceedance of the relevant state's assurance level has occurred.
    \265\ See 40 CFR 97.1002 (definitions of ``common designated 
representative,'' ``common designated representative's assurance 
level'' and ``common designated representative's share''), 
97.1006(c)(2), and 97.1025.
---------------------------------------------------------------------------

    The purpose of the proposed revision to the variability limits is 
to better align the variability limits for successive control periods 
with the regularly updated heat input data that would be used in the 
proposed process for dynamically setting the state emissions budgets. 
Under EPA's proposed budget-setting process, each emissions budget 
would be computed using the latest available reported heat input, which 
for each budget set for a control period in 2025 or a later year would 
be the heat input for the control period two years before the control 
period whose budget is being determined (for example, the state 
emissions budgets for the 2025 control period would be computed in 
early 2024 using the reported heat input for the 2023 control period). 
The proposed revised variability limits would be well coordinated with 
the budgets established using this dynamic budgeting process, because 
the percentage change in the actual heat input for the control period 
relative to the earlier-year heat input used in computing the state's 
emissions budget would be an appropriate measure of the degree of 
operational variability actually experienced by the state`s EGUs in the 
control period relative to the assumed operating conditions reflected 
in the state's budget. Setting a variability limit in this manner would 
be entirely consistent with the overall purpose of including 
variability limits in the assurance provisions.
    The reason the EPA is proposing to use the higher of a fixed 21% or 
the percentage change in heat input computed as just described is that 
the EPA believes that, for operational planning purposes, it can be 
useful for sources to know in advance of the control period a minimum 
value for what the variability limit could turn out to be. Because a 
state's actual total heat input for a control period is not known until 
after the end of the control period, this proposed revision would have 
the consequence that the state's final variability limit and assurance 
level for the control period also would not be known until after the 
control period. However, because the proposed rule provides that the 
variability limit would always be at least 21 percent, the sources in a 
state would be able to rely for planning purposes on the knowledge that 
the assurance level would always be at least 121 percent of the state's 
emissions budget for the control period. Advance knowledge of the 
minimum possible amount of the assurance level can be useful to 
sources, because one way a source can be confident that it will never 
incur the 3-for-1 allowance surrender ratio owed for emissions 
exceeding its state's assurance level is to plan its operations so as 
to never allow its own emissions to exceed its own share of the state's 
assurance level for the control period. Knowing that the variability 
limit would always be at least 21 percent would provide sources with 
values they could use for such planning purposes.
    The EPA believes that 21 percent is a reasonable value to use as 
the fixed variability limit for the 2023 and 2024 control periods and 
as the minimum variability limit for the control periods in 2025 and 
later years. To determine appropriate variability limits for the 
trading programs established in CSAPR, the EPA analyzed historical 
state-level heat input variability over the period from 2000 through 
2010 as a proxy for emissions variability, assuming constant emissions 
rates. See 76 FR 48265. Based on that analysis, the variability limits 
for ozone season NOX in both CSAPR and the CSAPR Update were 
set at 21 percent of each state's budget, and these variability limits 
for the NOX ozone season trading programs were then codified 
in 40 CFR 97.510 and 40 CFR 97.810, along with the respective state 
budgets. For the Revised CSAPR Update, the EPA performed an updated 
variability analysis for the twelve states being moved into the Group 3 
trading program in that rulemaking, evaluating historical state-level 
heat input variability over the period from 2000 through 2019. The 
updated analysis again resulted in a variability estimate of 21 
percent. The EPA also considered shorter time periods for the updated 
analysis and found that the resulting variability estimates were not 
especially sensitive to the particular time period analyzed.\266\ A 
further updated analysis for this rulemaking again results in a 
variability estimate of 21 percent for most states, and although the 
historical analysis indicates higher percentages for the two states 
with the smallest total heat input figures in this analysis--Delaware 
and New Jersey--the EPA does not consider it appropriate to raise the 
variability limit percentage beyond 21 percent for all other states 
based on the analytic results for these states, where small absolute 
heat input figures have resulted in larger variability 
percentages.\267\ Based on the consistent conclusions of these multiple 
analyses, the EPA proposes to continue using 21 percent as the fixed 
variability limit percentage for the 2023 and 2024 control periods and 
as the minimum value in the revised approach for establishing 
variability limits for the control periods in 2025 and later years.
---------------------------------------------------------------------------

    \266\ For details on the original variability analysis for 26 
states over the 2000-2010 period, including a description of the 
methodology, see the Power Sector Variability Final Rule TSD from 
the CSAPR (EPA-HQ-OAR-2009-0491-4454). For the updated variability 
analysis for twelve states for the 2000-2019 period, see the Excel 
file ``Historical Variability in Heat Input 2000 to 2019.xls.'' Both 
documents are available in the docket for this proposal.
    \267\ See the Excel document, ``OS Heat Input Variability 2000 
to 2021.xls'' for updated data, application of the CSAPR variability 
methodology, and results applied to heat input for 2000 through 2021 
for all states and for the region collectively.
---------------------------------------------------------------------------

    The EPA requests comment on the proposed rule to set variability 
limits for the 2023 and 2024 control periods as 21 percent of the 
respective revised state emissions budgets, consistent with the 
methodology used to determine the variability limits for these control 
periods set in the Revised CSAPR Update. In addition, the EPA requests 
comment on whether to set higher variability limits for Delaware and 
New Jersey for 2023 and 2024 based on the results of the most recent 
variability analysis. The EPA also requests comment on the proposed 
rule to establish a revised methodology for setting variability limits 
for all states for control periods in 2025 and later years, as 
discussed in this section.
6. Annual Recalibration of Allowance Bank
    As discussed in Section VII.B.1.b of this proposed rule, in this 
rulemaking, the EPA is proposing two revisions to the Group 3 trading 
program designed to better maintain the control stringency selected in 
the final rule in this rulemaking. The first proposed revision, 
discussed Section VII.B.4 of this proposed rule, is to adopt a dynamic 
budget-setting methodology that would allow state emissions budgets in 
future years to reflect more accurate information about the composition 
and utilization of the EGU fleet. The second, complementary, proposed 
revision is to recalibrate the bank of unused allowances each control 
period in order to prevent allowance surpluses in individual control 
periods from accumulating and adversely impacting the ability of the 
trading program in future control periods to maintain the selected 
control stringency identified in the rulemaking as necessary to address 
states' good neighbor obligations with respect to the 2015 ozone NAAQS.
    The EPA proposes to begin the bank recalibration process starting 
with the 2024 control period, after the compliance process for the 2023 
control period for all current and newly added states in the Group 3 
trading program

[[Page 20121]]

has been completed. The recalibration process for each control period 
would be carried out on or shortly after August 1 of that control 
period, two months after the compliance deadline for the previous 
control period, making the proposed date of the first recalibration 
August 1, 2024. The recalibrations could not take place significantly 
earlier than August 1 each year because compliance for the previous 
control period would not be completed until after June 1. However, 
because data on the amounts of allowances held are publicly available 
and the total quantity of allowances needed for compliance for the 
previous control period would be known shortly after the end of that 
control period, sources and other market participants would be able to 
ascertain with reasonable accuracy shortly after the end of each 
control period what degree of recalibration to expect for the next 
control period, even if the recalibration would not actually be carried 
out until the following August.
    Before undertaking a recalibration process each control period, the 
EPA would first determine whether the total amount of all banked Group 
3 allowances from previous control periods held in all facility 
accounts and general accounts in the Allowance Management System 
accounts exceeds the target bank amount. (For this purpose, no 
distinction would be made between banked Group 3 allowances issued from 
the state emissions budgets for previous control periods and banked 
Group 3 allowances issued through the conversion of previously banked 
Group 2 allowances.) If the total amount of banked Group 3 allowances 
does not exceed the target bank amount, the EPA would not carry out any 
recalibration for that control period. If the total amount of unused 
allowances does exceed the target bank amount, the EPA would determine 
for each account with holdings of banked Group 3 allowances the 
account-specific recalibrated amount of allowances, computed as the 
target bank amount multiplied by the account's total holdings of banked 
Group 3 allowances and divided by the total amount of banked Group 3 
allowances in all accounts, rounded up to the nearest allowance. 
Finally, the EPA would deduct from each account any banked Group 3 
allowances exceeding the account's recalibrated amount of banked 
allowances.
    As the target bank amount used in the recalibration process for 
each control period, the EPA proposes to use an amount determined as 
10.5 percent of the sum of the state emissions budgets for the control 
period, or half of the sum of the states' proposed minimum variability 
limits. The EPA has two reasons for proposing this amount. First, in 
the transition from CSAPR to the CSAPR Update, where the EPA set a 
target bank amount 1.5 times the sum of the variability limits, and in 
the transition from the CSAPR Update to the Revised CSAPR Update, where 
the EPA set a target bank amount of 1.0 times the sum of the 
variability limits, in each case the initial bank proved larger than 
necessary, as total emissions of all sources in the program were less 
than the budgets. Second, an analysis of year-to-year variability of 
heat input for the region covered by this proposed rule suggests that 
the regional heat input for an individual year can be expected to vary 
by up to 10.5 percent above or below the central trend with 95% 
confidence. This variability analysis is an application to the entire 
region of the variability analysis EPA has performed for individual 
states to establish the variability limit of 21 percent for the states 
in the trading program.\268\ When the analysis is performed at the 
regional level, the data show less year-to-year variation than when the 
analysis is performed at the individual state level. Within the trading 
program structure, it is logical to use variability analyzed at the 
level of individual states to set the variability limits, which apply 
at the level of individual states, while using variability analyzed at 
the level of the overall region to set a target level for a bank, which 
will apply at the level of the overall program.
---------------------------------------------------------------------------

    \268\ See the Power Sector Variability Final Rule TSD from 
CSAPR, available at https://www.epa.gov/csapr/power-sector-variability-final-rule-tsd for a description of the methodology. 
Also see the Excel document ``OS Heat Input--Variability 2000 to 
2021.xls'' for updated data, application of the CSAPR variability 
methodology, and results applied to heat input for 2000 through 2021 
for all states and for the region collectively.
---------------------------------------------------------------------------

    The annual bank recalibrations will help maintain the control 
stringency determined to be necessary to address states' good neighbor 
obligations for the 2015 ozone NAAQS. Moreover, the proposed 
recalibrations are less complex than alternative approaches would be. 
For example, the NOX Budget Trading Program established in 
the NOX SIP Call also contained provisions designed to 
prevent excessive accumulations of banked allowances on program 
stringency, but those provisions--under the name ``progressive flow 
control''--introduced uncertainty as to whether banked allowances would 
be usable to offset one ton of emissions or less than one ton of 
emissions in the current control period. The EPA considers the 
recalibration mechanism proposed here to be simpler with less 
associated uncertainty.
    Finally, the EPA observes that the proposed recalibration mechanism 
is entirely consistent with the Agency's existing authority under 40 
CFR 97.1006(c)(6) to ``terminate or limit the use and duration'' of any 
Group 3 allowance ``to the extent the Administrator determines is 
necessary or appropriate to implement any provision of the Clean Air 
Act.'' The Administrator proposes to determine that the recalibrations 
are both necessary and appropriate to ensure that the control 
stringency selected in this rulemaking is maintained and states' good 
neighbor obligations with respect to the 2015 ozone NAAQS are 
addressed.
    The EPA requests comment on the proposed bank recalibration 
provisions and the proposed use of a target bank amount computed as 
10.5 percent times the sum of the state emissions budgets for each 
control period.
7. Unit-Specific Backstop Daily Emissions Rates
    While the identified EGU emissions reductions in Section VI of this 
proposed rule are incentivized and secured primarily through the 
corresponding seasonal state emissions budgets (expressed as a seasonal 
tonnage limit for all covered EGUs within a state's borders) described 
earlier, the EPA is also incorporating backstop daily emissions rates 
of 0.14 lb/mmBtu for coal-fired steam units serving generators with 
nameplate capacity greater than or equal to 100 MW in covered states. 
The backstop emissions rates will first apply in 2024 for coal-fired 
steam units with existing SCR controls, and in 2027 for coal-fired 
steam units currently without SCR controls. For a unit that exceeds its 
applicable backstop daily emissions rate on any day, all emissions on 
that day exceeding the emissions that would have occurred at the 
backstop daily emissions rate will be subject to a 3-for-1 allowance 
surrender ratio instead of the normal 1-for-1 allowance surrender 
ratio. See Appendix A of the Ozone Transport Policy Proposed Rule TSD 
for a list of coal-fired steam units serving generators larger than or 
equal to 100 MW in covered states for which the identified backstop 
emissions rate would apply starting in either 2024 or 2027.
    The EGU NOX Mitigation Strategies Proposed Rule TSD 
describes the methodology for deriving the 0.14 lb/mmBtu daily rate 
limit in more detail. The methodology is summarized as follows. First, 
consistent with

[[Page 20122]]

stakeholders' focus on providing daily assurance of control operation, 
EPA determined that daily (as opposed to hourly or monthly) was an 
appropriate time metric for backstop emissions rate limits instituted 
to ensure operation of controls on high ozone days. The EPA derived the 
0.14 lb/mmBtu daily rate limit by determining the particular level of a 
daily rate that would be comparable in stringency to the 0.08 lb/mmBtu 
seasonal emissions rate that the Agency has identified as reflecting 
SCR optimization at existing units.\269\ The EPA first conducted an 
empirical exercise using reported daily emissions rate data from 
existing, SCR-controlled coal units that were emitting at or below 0.08 
lb/mmBtu on a seasonal average basis. Recognizing that this seasonal 
rate reflects the average across a unit's range of varying daily rates 
reflecting different operation conditions, including some occasions 
when the SCR control may not be operating or may not be fully 
optimized, the EPA identified the upper end of the daily emissions rate 
range for these units. When the EPA examined the daily emissions rate 
pattern for these units considered to be optimizing their SCRs on a 
seasonal basis, the EPA observed that over 95 percent of the time, 
their daily rates were below 0.14 lb/mmBtu. In addition, for these 
units, less than 1 percent of their seasonal emissions would exceed 
this daily rate limit.
---------------------------------------------------------------------------

    \269\ See page 24 of ``Guidance for 1-hour SO2 
Nonattainment Area SIP Submission'' at https://www.epa.gov/sites/default/files/2016-06/documents/20140423guidance_nonattainment_sip.pdf. ``A limit based on the 30-
day average of emissions, for example, at a particular level is 
likely to be a less stringent limit than a 1-hour limit at the same 
level 1 since the control level needed to meet a 1-hour limit every 
hour is likely to be greater than the control level needed to 
achieve the same limit on a 30-day average basis.''
---------------------------------------------------------------------------

    The EPA conducted this analysis to be consistent with the 
methodology developed in the 2014 1-hr SO2 attainment area 
guidance for identifying ``comparably stringent'' emissions rates over 
varying time-periods.\270\ Appendix C of that guidance describes a 
series of steps that involve: (1) Compiling emissions data to reflect a 
distribution of emissions rates with various averaging times, (2) 
determining the 99th percentile of the average emissions values 
compiled in the previous step, and then (3) applying ``adjustment 
factors'' or ratios of the 99th percentile values to emissions rates to 
convert them (usually from a short-term rate to a longer-term rate). In 
this case, the EPA applied the methodology in reverse to convert a 
longer-term limit (the seasonal rate of 0.08 lb/mmBtu which was assumed 
to be equal to a 30-day rate of 0.08 lb/mmBtu) to a comparably 
stringent short-term limit (a daily rate of 0.14 lb/mmBtu). The EPA 
requests comment on the proposed incorporation of a backstop daily 
emissions rate element into the Group 3 trading program and on the 
proposed methodology for determining the daily emissions rate of 0.14 
lb/mmBtu.
---------------------------------------------------------------------------

    \270\ See Guidance for 1-Hour SO2 Nonattainment Area 
SIP Submissions available at https://www.epa.gov/sites/default/files/2016-06/documents/20140423guidance_nonattainment_sip.pdf.
---------------------------------------------------------------------------

    In addition, the EPA requests comment on application of the 
backstop daily emissions rates in the event that an affected unit finds 
it more economic to retire shortly after the start of the 2027 ozone 
season in lieu of investing in new NOX post-combustion 
control technology. This proposed rule's state emissions budgets would 
require emissions reductions starting in 2026 commensurate with SCR 
retrofits at these units regardless of when these unit-level backstop 
rates are subsequently imposed. The EPA recognizes that such retrofits 
in practice may be less environmentally efficient compared to imminent 
retirement that would potentially yield lower cumulative emissions of 
NOX and multiple other pollutants over time. The EPA also 
recognizes that several coal-fired EGUs have been considering 
retirement by 2028 under compliance pathways available under Clean 
Water Act effluent guidelines \271\ and the coal combustion residuals 
rule under the Resource Conservation and Recovery Act.\272\ 2028 also 
represents the end of the second planning period under the Regional 
Haze program, and thus is a significant year in states' planning of 
strategies to make reasonable progress towards natural visibility at 
Class I areas.\273\ To facilitate a potentially economic and 
environmentally superior unit-level compliance response across these 
programs that nonetheless maintains the NOX reductions 
required by the state budgets from 2026 forward in this proposed rule, 
the EPA is requesting comment on potentially deferring the application 
of the backstop daily rate for large coal EGUs that submit written 
attestation to the EPA that they make an enforceable commitment to 
retire by no later than the end of calendar year 2028. EPA anticipates 
that units failing to retire contrary to their attestation would become 
subject to the backstop emissions rate in the 2029 ozone season, and 
would likely be subject to other appropriate enforcement proposed rule 
under the Clean Air Act or other relevant authorities.
---------------------------------------------------------------------------

    \271\ See 40 CFR 423.11(w).
    \272\ See 40 CFR 257.103(b).
    \273\ See 40 CFR 51.308(f).
---------------------------------------------------------------------------

8. Unit-Specific Emissions Limitations Contingent on Assurance Level 
Exceedances
    As emphasized by the D.C. Circuit in its decision invalidating 
CAIR, under the CAA's good neighbor provision, emissions ``within the 
State'' that contribute significantly to nonattainment or interfere 
with maintenance of a NAAQS in another state must be prohibited. North 
Carolina v. EPA, 531 F.3d 896, 906-908 (D.C. Cir. 2008). The CAIR 
trading programs contained no provisions limiting the degree to which a 
state could rely on net purchased allowances as a substitute for making 
in-state emissions reductions, an omission which the court found was 
inconsistent with the requirements of the good neighbor provision. Id. 
In response to that holding, the EPA established the CSAPR trading 
programs' assurance provisions to ensure that, in the context of a 
flexible trading program, the emissions reductions required under the 
good neighbor provision in fact will take place within the state. The 
EPA believes the assurance provisions have generally been successful in 
achieving that objective, as evidenced by the fact that since the 
assurance provisions took effect in 2017, out of the nearly 300 
instances where a given state's compliance with the assurance 
provisions of a given CSAPR trading program for a given control period 
has been assessed, a state's collective emissions have exceeded the 
applicable assurance level only four times.
    Unfortunately, the EPA also recognizes that the assurance 
provisions' very good historical compliance record is not good enough. 
The four past exceedances all occurred under the Group 2 trading 
program: Sources in Mississippi collectively exceeded their applicable 
assurance levels in the 2019 and 2020 control periods, and sources in 
Missouri collectively exceeded their applicable assurance levels in the 
2020 and 2021 control periods.\274\ Both of the

[[Page 20123]]

exceedances by Missouri sources could easily have been avoided if the 
owner and operator of several SCR-equipped, coal-fired steam units had 
not chosen to idle the units' controls and rely instead on net out-of-
state purchased allowances. The exceedances were large, and ample 
quantities of allowances to cover the resulting 3-for-1 allowance 
surrender requirements were purchased in advance, suggesting that the 
assurance level exceedances may have been anticipated as a possibility. 
In the case of the Mississippi exceedances, the exceedances were 
smaller, operational variability (manifesting as increased heat input) 
appears to have been a material contributing factor, and the EPA has 
not concluded that the owners and operators anticipated the 
exceedances. However, an additional contributing factor was the fact 
that several large, gas-fired steam units without SCR controls emitted 
NOX at average rates much higher than the average emissions 
rates the same units had achieved in previous control periods. In 
short, while the Missouri exceedances appear far more significant, 
EPA's analysis indicates that all four past exceedances could have been 
avoided if the units most responsible had achieved emissions rates more 
comparable to the same units' previous performance. In EPA's view, the 
operation of the Missouri units in particular--although not prohibited 
by the current regulatory requirements--cannot be reconciled with the 
statutory requirements of the good neighbor provision. The fact that 
such operation is not prohibited by the current regulations therefore 
indicates a deficiency in the current regulatory requirements.
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    \274\ Information on the assurance level exceedances in the 2019 
and 2020 control periods is available in the final notices 
concerning EPA's administration of the assurance provisions for 
those control periods. 85 FR 53364 (August 28, 2020); 86 FR 52674 
(September 22, 2021). The EPA will publish an analogous final notice 
for the 2021 control period by October 1, 2022, and will also 
publish a preliminary notice by August 1, 2022. At this time, 
information on the relevant Missouri assurance level for the 2021 
control period is available at 40 CFR 97.806(c)(2) and 97.810 and 
preliminary data on Missouri units' emissions of NOX 
during the 2021 ozone season are available at ampd.epa.gov.
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    To correct the deficiency in the regulatory requirements, the EPA 
proposes in this rulemaking to revise the Group 3 trading program 
regulations to establish an additional emissions limitation to more 
effectively deter avoidable assurance level exceedances. Because the 
pollutant involved is ozone season NOX and the particular 
sources for which deterrence is most needed are located in states that 
are proposed to transition soon from the Group 2 trading program to the 
Group 3 trading program, the EPA is proposing to promulgate the 
strengthening provisions as revisions to the Group 3 trading program 
regulations rather than the Group 2 trading program regulations.\275\
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    \275\ The EPA believes that the occurrence of avoidable 
assurance level exceedances under the Group 2 trading program, 
combined with the express statutory directive that good neighbor 
obligations must be addressed ``within the state,'' and through 
``prohibition,'' would also provide a sufficient legal basis for the 
Agency to promulgate the same revisions to the assurance provisions 
for all the other CSAPR trading programs. The EPA is not proposing 
to do so at this time because the Agency has seen no reason to 
expect exceedances of the assurance levels under any of the other 
CSAPR trading programs by any of the states that will remain subject 
to the respective trading programs after this rulemaking, except 
possibly by Missouri under the CSAPR NOX Annual Trading 
Program. The EPA expects that reductions in Missouri's seasonal 
NOX emissions sufficient to comply with the proposed 
provisions of the revised Group 3 trading program, including the 
secondary emissions limitations, would also prevent exceedances of 
Missouri's currently applicable assurance level for annual 
NOX emissions.
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    The two current emissions-related compliance requirements in the 
Group 3 trading program regulations are both structured in the form of 
requirements to hold allowances. The first requirement applies at the 
source level: Specifically, at the compliance deadline after each 
control period, the owners and operators of each source covered by the 
program must surrender a quantity of allowances that is determined 
based on the emissions from the units at the source during the control 
period. The second requirement applies at the designated representative 
level (which typically is the owner or operator level): If the state's 
sources collectively emit in excess of the state's assurance level, the 
owners and operators of each set of sources determined to have 
contributed to the exceedance must surrender an additional quantity of 
allowances. As long as a source's owners and operators comply with 
these two allowance surrender requirements (and meet certain other 
requirements not related to the amounts of the sources' emissions), 
they are in compliance with the program.
    In light of the operation of the Missouri sources, the EPA is 
doubtful that strengthening the assurance provisions by increasing 
allowance surrender requirements at the unit, source, or designated 
representative level would create a sufficient deterrent. Accordingly, 
the EPA is proposing instead to add a new, unit-level emissions 
limitation structured as a prohibition to emit NOX in excess 
of a defined amount. A violation of the prohibition would not trigger 
additional allowance surrender requirements beyond the surrender 
requirements that would otherwise apply, but would trigger the possible 
application of the CAA's enforcement authorities. Because the purpose 
of the new unit-level emissions limitation would be to deter conduct 
causing exceedances of a state's assurance level, the EPA proposes to 
condition applicability of the new limitation on (1) the occurrence of 
an exceedance of the state's assurance level for the control period, 
and (2) the apportionment of at least some of the responsibility for 
the assurance level exceedance to the set of units represented by the 
unit's designated representative. Apportionment of responsibility for 
the assurance level exceedance would be carried out according to the 
existing assurance provision procedures and would therefore depend on 
the designated representative's shares of both the state's total 
emissions for the control period and the state's assurance level for 
the control period. The new emissions limitation would be in addition 
to, not in lieu of, the other requirements of the Group 3 trading 
program. This point would be made explicit by relabeling the source-
level allowance holding requirement, currently called the ``emissions 
limitation,'' as the ``primary emissions limitation'' and labeling the 
new unit-level requirement as the ``secondary emissions limitation.'' 
(The regulations label the designated representative-level requirement 
as ``compliance with the . . . assurance provisions.'')
    The EPA proposes to define the unit-level secondary emissions 
limitation by formula to reflect the amount of additional 
NOX emissions caused by the unit's deviation from a 
benchmark seasonal average NOX emissions rate during the 
control period, where the benchmark seasonal average NOX 
emissions rate for the unit would be based on emissions rates the unit 
has achieved in the past plus a 25 percent margin. The EPA also 
proposes to use a floor for past performance of 0.08 lb/mmBtu (yielding 
0.10 lb/mmBtu when the 25 percent margin is added), exclude control 
periods where the unit operated in less than 10 percent of the hours 
(in order to avoid data that might be unrepresentative), and screen out 
instances where the amount of additional emissions caused by the poor 
performance is less than 50 tons. Specifically:
     The EPA proposes to define a unit's secondary emissions 
limitation for a control period, in tons of NOX, as the sum 
of 50 tons plus the product of (1) the unit's benchmark seasonal 
average emissions rate times (2) the unit's actual heat input for the 
control period, except that if the unit operated during less than 10 
percent of the hours in the control period, no secondary emissions 
limitation would be defined for the unit for that control period.
     The EPA proposes to calculate the benchmark seasonal 
average NOX

[[Page 20124]]

emissions rate for a unit for this purpose, in lb NOX/mmBtu, 
as the higher of (1) 0.10 lb/mmBtu or (2) 125 percent of the unit's 
lowest seasonal average NOX emissions rate in a previous 
control period under the CSAPR NOX Ozone Season Group 1, 
Group 2, or Group 3 Trading Program, excluding any control periods 
where the unit operated for less than 10 percent of the hours in the 
ozone season.\276\
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    \276\ In proposing a formulation for a benchmark rate for the 
specific regulatory purpose of defining a secondary emissions 
limitation under the Group 3 trading program, the EPA is not 
expressing a view that the same formulation of a benchmark rate 
would be suitable for any other regulatory purpose.
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    Table VII.B.8-1 shows the secondary emissions limitations that the 
proposed formula would have produced and which units would have 
exceeded those limitations if the limitations and formula had been in 
effect for the Group 2 trading program in 2019, 2020, and 2021 when 
assurance level exceedances occurred in Mississippi and Missouri. The 
EPA believes that in each case the formula functions in a reasonable 
manner, and the units identified as exceeding their respective 
secondary emissions limitations are sources for which an enforcement 
deterrent under CAA sections 113 and 304 would have been appropriate to 
compel better control of NOX emissions.

     Table VII.B.8-1--Illustrative Results of Applying Proposed Secondary Emissions Limitation in Previous Instances of Assurance Level Exceedances
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Benchmark NOX                       Secondary
                                                                      emissions rate     Actual NOX       emissions        Actual NOX       Exceedance
             Owner/operator                         Unit                (lb/mmBtu)     emissions rate     limitation       emissions          (tons)
                                                                                         (lb/mmBtu)         (tons)           (tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Mississippi--2019
    Miss. Power........................  Watson 4..................            0.137            0.176              458              524               66
    Miss. Power........................  Watson 5..................            0.215            0.349            1,247            1,943              696
Mississippi--2020
    Entergy Miss.......................  Andrus 1..................            0.224            0.289            1,219            1,508              289
    Miss. Power........................  Watson 5..................            0.215            0.286            1,086            1,381              295
Missouri--2020
    Assoc. Elec. Coop..................  New Madrid 1..............            0.135            0.670              961            4,524            3,563
    Assoc. Elec. Coop..................  New Madrid 2..............            0.131            0.497              866            3,108            2,242
    Assoc. Elec. Coop..................  Thomas Hill 1.............            0.123            0.526              374            1,384            1,010
    Assoc. Elec. Coop..................  Thomas Hill 2.............            0.122            0.537              548            2,187            1,639
    Assoc. Elec. Coop..................  Thomas Hill 3.............            0.104            0.195              780            1,374              594
Missouri--2021
    Assoc. Elec. Coop..................  New Madrid 1..............            0.135            0.652              353            1,466            1,113
    Assoc. Elec. Coop..................  New Madrid 2..............            0.131            0.611            1,054            4,700            3,646
    Assoc. Elec. Coop..................  Thomas Hill 1.............            0.123            0.146              421              440               19
    Assoc. Elec. Coop..................  Thomas Hill 2.............            0.122            0.400              600            1,801            1,201
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For further illustrations of the application of the proposed 
formula and secondary emissions limitation to other units in the states 
proposed to be subject to the expanded Group 3 trading program in the 
control periods from 2016 through 2021, see the spreadsheet 
``Illustrative Calculations Using Proposed Secondary Emissions 
Limitation Formula'', available in the docket. The EPA notes that, with 
the exception of the units listed in Table VII.B.8-1, no unit shown in 
the spreadsheet as having emissions exceeding the illustrative 
secondary emissions limitation calculated for the unit would have 
violated the proposed prohibition because no violation would occur in 
the absence of an exceedance of the assurance level and apportionment 
of responsibility for a share of the exceedance to the unit under the 
assurance provisions.
    The EPA requests comment on the proposal to establish a secondary 
emissions limitation for the Group 3 trading program as described in 
this section. The EPA specifically requests comment on the proposed 
form of the secondary emissions limitation, the proposed formula for 
computing each unit's secondary emissions limitation, and the proposed 
values for the screening parameters used in the calculations.
9. Unit-Level Allowance Allocation and Recordation Procedures
    In the Revised CSAPR Update, the EPA established default procedures 
for allocating CSAPR NOX Ozone Season Group 3 allowances 
(``Group 3 allowances'') in amounts equal to each state emissions 
budget for each control period among the sources in the state for use 
in complying with the Group 3 trading program. The EPA also provided 
states with several options to submit SIP revisions which, if approved, 
would result in the replacement of EPA's allowance allocations with 
state-determined allowance allocations for the 2022 control period and 
beyond. The current regulations (i.e., before this proposed rule) 
provide that EPA's allocations and allocation procedures apply for the 
2021 control period and, by default, for subsequent control periods 
unless and until a state provides state-determined allowance 
allocations under an approved SIP revision.
    The current default allocation process for the Group 3 trading 
program established in the Revised CSAPR Update involves three main 
steps. First, a portion of each state emissions budget for each control 
period is reserved for potential allocation to units that are subject 
to allowance holding requirements and that would not otherwise receive 
allowance allocations in the overall allocation process. Under the 
current Group 3 trading programs, the reserved allowances are made 
available generally (but not exclusively \277\) to ``new'' units--which 
for purposes of the Revised CSAPR Update means units commencing 
commercial operation on or after January 1, 2019--through a ``new unit 
set-aside'' established for qualifying units in each state and, if 
areas of Indian country exist within the state's borders, a separate 
``Indian country new unit set-

[[Page 20125]]

aside'' for qualifying units in such Indian country. Second, in advance 
of each control period, the unreserved portion of the state budget is 
allocated among the state's eligible ``existing'' units--which for 
purposes of the Revised CSAPR Update generally means units that 
commenced commercial operation before January 1, 2019--and the 
allocations are recorded in the respective sources' compliance 
accounts. Finally, after the control period but before the compliance 
deadline by which sources must hold allowances to cover their emissions 
for the control period, allowances from the reserved portions of the 
budget are allocated to qualifying units, any remaining reserved 
allowances not allocated to qualifying units are allocated among the 
state's existing units, and the allocations are recorded in the 
respective sources' compliance accounts.
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    \277\ The units qualifying for allocations from a new unit set-
aside may include not only units that have recently started 
operating but also units that previously received, but are no longer 
eligible to receive, allocations from the unreserved portion of the 
budget as ``existing'' units.
---------------------------------------------------------------------------

    In this rulemaking, the EPA would retain the overall three-step 
allocation process summarized above but is proposing revisions to each 
step to better address units in Indian country and to better coordinate 
the unit-level allocation process with the proposed dynamic budget-
setting process discussed in Section VII.B.4 of this proposed rule. 
Like the allocation process established in CSAPR, the CSAPR Update, and 
the Revised CSAPR Update, the revised process proposed in this 
rulemaking would be designed to provide default allowance allocations 
to all units that are subject to allowance holding requirements, 
including, for the first time under any CSAPR trading program, an 
existing EGU in Indian country not covered by a state's CAA 
implementation planning authority. The proposed revisions to the three 
steps are discussed in Sections VII.B.4.a, VII.B.4.b, and VII.B.4.c of 
this proposed rule, respectively.
    Echoing the approach to unit-level allocations followed in CSAPR, 
the CSAPR Update, and the Revised CSAPR Update, in this rulemaking, EPA 
is again proposing to provide states with several options to submit SIP 
revisions which, if approved, would result in the replacement of EPA's 
default allocations with state-determined allocations for subsequent 
control periods. Specifically, the proposed regulations would provide 
that EPA's allocations and allocation procedures will apply for the 
2023 control period and, by default, for subsequent control periods 
unless and until a state provides state-determined allocations under an 
approved SIP revision. The options to submit SIP revisions that would 
accomplish this purpose are discussed in Section VII.D of this 
document. Similarly, for a covered area of Indian country not subject 
to a state's CAA implementation planning authority, a tribe could elect 
to work with the EPA under the Tribal Authority Rule to develop a full 
or partial tribal implementation plan under which the tribe would 
determine allowance allocations that would replace EPA's default 
allocations for subsequent control periods.
a. Set-Asides of Portions of State Emissions Budgets for New Units
    As the first step in the default allocation process that the EPA 
has applied under CSAPR, the CSAPR Update, and the Revised CSAPR Update 
for any control period where a state does not employ an alternative 
allocation process pursuant to an approved SIP revision, EPA has 
reserved a portion of the state's emissions budget for potential 
allocation to units that are subject to allowance holding requirements 
and that would not otherwise receive allowance allocations in the 
overall allocation process. Consistent with the budget-setting approach 
in those rulemakings, where the state emissions budgets for all future 
control periods were determined in the initial rulemakings, the amounts 
of the reserved portions of the budgets were also determined in the 
initial rulemakings.\278\
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    \278\ Under the current regulations for each of the CSAPR 
trading programs, when a unit that has received allocations as an 
``existing'' unit ceases operation, after a specified number of 
control periods the unit loses the allocations, which are then 
allocated to the state's new unit set-asides for subsequent control 
periods.
---------------------------------------------------------------------------

    The units for which portions of the budgets were reserved in set-
asides have fallen into two main categories: First, units for which the 
data needed to determine allowance allocations does not exist at the 
time when the allocations for other units were being determined--i.e., 
``new'' units \279\--and second, units that would be left out if a 
state chooses to replace EPA's default allocations with state-
determined allocations--i.e., any units in Indian country not covered 
by a state's CAA implementation planning authority. Because there were 
no existing units in what the EPA understood to be Indian country for 
purposes of CSAPR, the CSAPR Update, and the Revised CSAPR Update, 
potential units in Indian country were considered to be a subcategory 
of ``new'' units, and the two types of set-asides that have been 
created are ``new unit set-asides'' and ``Indian country new unit set-
asides.'' The principal difference between these two types of set-
asides under the regulations for all of the CSAPR trading programs has 
been that a state can take over administration of the allowances 
allocated to a new unit set-aside from the EPA through an approved SIP 
revision but cannot take over administration of the allowances 
allocated to an Indian country new unit set-aside.
---------------------------------------------------------------------------

    \279\ A unit that has received allocations as an ``existing'' 
unit, then loses its allocations because of non-operation, and then 
later resumes operation is treated as a type of ``new'' unit for 
allocations purposes.
---------------------------------------------------------------------------

    In this rulemaking, the EPA is proposing several revisions 
affecting the establishment of set-asides. The first proposed revision, 
which is largely unrelated to the other aspects of this rulemaking, 
would update the regulations for the Group 3 trading program \280\ to 
reflect the D.C. Circuit's holding in ODEQ v. EPA that the relevant 
states have initial CAA implementation planning authority in non-
reservation areas of Indian country until displaced by a demonstration 
of tribal jurisdiction over such an area.\281\ Consistent with this 
holding, EPA is proposing to revise language in the Group 3 trading 
program regulations that, for purposes of allocating allowances from a 
given state's emissions budget, currently distinguishes between (1) the 
set of units within the state's borders that are not in Indian country 
and (2) the set of units within the state's borders that are in Indian 
country. As revised, the provisions would distinguish between (1) the 
set of units within the state's borders that are not in Indian country 
or are in areas of Indian country covered by the state's CAA 
implementation planning authority and (2) the set of units within the 
state's borders that are in areas of Indian country not covered by the 
state's CAA implementation planning authority. The revised language 
would more accurately distinguish which units are, or are not, covered 
by a state's CAA implementation planning authority, which is the 
underlying purpose for which the term ``Indian country'' is currently 
used in the allowance allocation provisions. The effect of the proposed 
revision would be that any

[[Page 20126]]

units located in areas of ``Indian country'' as defined in 18 U.S.C. 
1151 that are covered by a state's CAA implementation planning 
authority would be treated for allowance allocation purposes in the 
same manner as units in areas of the state that are not Indian country, 
consistent with the ODEQ holding.\282\
---------------------------------------------------------------------------

    \280\ As further discussed in Section VII.B.12 of this proposed 
rule, the EPA is also proposing to make this revision to the 
regulations for the other CSAPR trading programs in addition to the 
Group 3 trading program.
    \281\ For additional discussion of the ODEQ v. EPA decision and 
other issues related to the CAA implementation planning authority of 
states, tribes, and the EPA in various areas of Indian country, see 
Section IV.C.2 of this proposed rule.
    \282\ The EPA notes that the units that would be treated for 
allocation purposes in the same manner as units not in Indian 
country would include units in any areas of Indian country subject 
to a state's CAA implementation planning authority, whether those 
are non-reservation areas (consistent with ODEQ) or reservation 
areas (such as areas of Indian country within Oklahoma's borders 
covered by the EPA's October 1, 2020 approval of Oklahoma's request 
under SAFETEA, as discussed in Section IV.C.2 of this proposed 
rule).
---------------------------------------------------------------------------

    The remaining proposed revisions, which are interrelated, concern 
the types of set-asides that in the context of this proposal will best 
accomplish the goal of ensuring the availability of allocations to 
units that are subject to allowance holding requirements and that would 
not otherwise receive allowance allocations. One proposed revision to 
the types of set-asides addresses allocations to existing units in 
Indian country. The revised geographic scope of the Group 3 trading 
program under this proposal would for the first time include an 
existing EGU in Indian country not covered by a state's CAA 
implementation planning authority--the Bonanza coal-fired unit in the 
Uintah and Ouray Reservation within Utah's borders. In order to provide 
an option for Utah (or a similarly situated state in the future) to 
replace EPA's default allowance allocations to most existing units with 
state-determined allocations through a SIP revision while continuing to 
ensure the availability of a default allocation to the Bonanza unit (or 
similarly situated units in the future), the EPA proposes to revise the 
Group 3 trading program regulations to provide for ``Indian country 
existing unit set-asides.'' Specifically, for each state and for each 
control period where the inventory of units used to compute the state's 
emissions budget includes one or more existing units \283\ in an area 
of Indian country not covered by the state's CAA implementation 
planning authority, the EPA would reserve a portion of the state's 
emissions budget in an Indian country existing unit set-aside for the 
unit or units. The amount of each Indian country existing unit set-
aside would equal the sum of the default allocations that the units 
covered by the set-aside would receive if the allocations to all 
existing units within the state's borders were computed according to 
EPA's default allocation procedure (which is discussed in Section 
VII.B.9.b of this proposed rule). Immediately after determining the 
amount of a state's emissions budget for a control period (and after 
reserving a portion for potential allocation to new units, as discussed 
below), the EPA would first determine the default allocations for all 
existing units within the state's borders, then allocate the 
appropriate quantity of allowances to the Indian country existing unit 
set-aside, then allocate the allowances from the set-aside to the 
covered units in Indian country, and finally record the allocations in 
the sources' compliance accounts at the same time as the allocations to 
other sources not in Indian country. The existence of the Indian 
country existing unit set-aside thus would have no substantive effect 
unless and until the relevant state chose to replace EPA's default 
allowance allocations through a SIP revision, in which case the state 
would have the ability to establish state-determined allocations for 
the units subject to the state's CAA implementation planning authority 
while the EPA would continue to administer the Indian country existing 
unit set-aside for the units in Indian country not covered by the 
state's CAA implementation planning authority.\284\ The EPA believes 
the proposal to establish Indian country existing unit set-asides would 
accomplish the objective of allowing states to control allowance 
allocations to units covered by their CAA implementation planning 
authority while providing equitable allocations to units in Indian 
country not covered by such authority.
---------------------------------------------------------------------------

    \283\ In coordination with the dynamic budgeting process 
discussed in Section VII.B.4 of this proposed rule, each unit 
included in the unit inventory used to determine a state's emissions 
budget for a given control period in 2025 or a later year would be 
considered an ``existing'' unit for that control period for purposes 
of the determination of unit-level allowance allocations. In other 
words, there would no longer be a single fixed date that would 
divide ``existing'' from ``new'' units.
    \284\ As noted in Section VII.D, of this proposed rule a tribe 
could elect to work with EPA under the Tribal Authority Rule to 
develop a full or partial tribal implementation plan under which the 
tribe would determine allowance allocations for units in the 
relevant area of Indian country that would replace EPA's default 
allocations for subsequent control periods.
---------------------------------------------------------------------------

    The remaining revisions to the types of set-asides address the set-
asides used to ensure availability of allowance allocations to new 
units in light of the division of the budget for existing units into a 
reserved portion for existing units in Indian country and an unreserved 
portion for other existing units. Under the current Group 3 trading 
program regulations, allowances for new units are provided from 
separate new unit set-asides and Indian country new unit set-asides. 
The EPA proposes to combine these two types of set-asides starting with 
the 2023 control period by eliminating the Indian country new unit set-
asides and expanding eligibility for allocations from the new unit set-
asides to include units anywhere within the relevant states' borders. 
However, as with the Indian country new unit set-asides under the 
current regulations, the EPA would continue to administer the new unit 
set-asides in the event a state chose to replace EPA's default 
allocations to existing units with state-determined allocations, 
thereby ensuring the availability of allocations to any new units not 
covered by a state's CAA implementation planning authority.
    The reason for the proposed revisions to the new unit set-asides 
and Indian country new unit set-asides is to avoid unnecessary and 
potentially inequitable changes to the degree to which individual 
existing units contribute to, or benefit from, the new unit set-asides. 
Under the current regulations, the allowances used to establish these 
set-asides are reserved from each state emissions budget before 
determination of the allocations from the unreserved portion of the 
budget to existing units, so that certain existing units--generally 
those receiving the largest allocations--contribute to creation of the 
set-asides through roughly proportional reductions in their 
allocations. Later, if any allowances in a set-aside are not allocated 
to qualifying new units, the remaining allowances are reallocated to 
the existing units in proportion to their initial allocations from the 
unreserved portion of the budget, so that certain existing units--
again, generally those receiving the largest allocations--benefit from 
the reallocations in rough proportion to their previous 
contributions.\285\ The EPA believes maintaining this symmetry, where 
the same existing units--whether in Indian country or not--both 
contribute to and potentially benefit from the set-asides, is a 
reasonable policy objective, and doing so requires that the EPA 
continue to administer the new unit set-asides in the event a state 
chooses to replace EPA's default allocations to existing units with 
state-determined allocations, because otherwise the EPA would be unable 
to ensure that the units in Indian country would receive an appropriate

[[Page 20127]]

share of any reallocated allowances.\286\ Since the principal 
difference between the new unit set-asides and the Indian country new 
unit set-asides under the current regulations is that the EPA continues 
to administer the Indian country new unit set-asides in the event a 
state chooses to replace EPA's default allocations with state-
determined allocations, if under the revised regulations the EPA would 
need to continue to administer the new unit set-asides, then there 
would no longer be any reason to establish separate Indian country new 
unit set-asides.
---------------------------------------------------------------------------

    \285\ Allowances from an Indian country new unit set-aside that 
are not allocated to qualifying new units are first transferred to 
the state's new unit set-aside, and if the allowances are still not 
allocated to qualifying new units, the allowances are then 
reallocated to the state's existing units.
    \286\ If units in Indian country were unable to share in the 
benefits of reallocation of allowances from the new unit set-asides, 
it would be possible to achieve a different form of symmetry by 
simultaneously exempting the units in Indian country from the 
obligation to share in the contribution of allowances to the new 
unit set-asides. However, some stakeholders might view this 
alternative as potentially inequitable because existing units in 
Indian country would then make no contributions toward the new unit 
set-aside while other existing units would still be required to do 
so.
---------------------------------------------------------------------------

    With respect to the total amounts of allowances that would be set 
aside for potential allocation to new units from the emissions budgets 
for each state, for the control periods in 2023 and 2024 (but not for 
subsequent control periods, as discussed below), EPA proposes to 
establish total set-aside amounts equal to the projected amounts of 
emissions from any planned units in the state for the control period, 
plus an additional 2% of the state emissions budget to address any 
unknown new units. For example, if planned units in a state are 
projected to emit 3% of the state's NOX ozone season 
emissions budget, then the new unit set-aside for the state would be 
set at 5 percent, which is the sum of the minimum 2% set-aside plus an 
additional 3 percent for planned units. This is the same approach 
previously used to establish the amounts of new unit set-asides in 
CSAPR, the CSAPR Update, and the Revised CSAPR Update for all the CSAPR 
trading programs. See, e.g., 76 FR 48292 (August 8, 2011). As under the 
Revised CSAPR Update, EPA proposes to make an exception for New York 
for the 2023 and 2024 control periods, establishing a total new unit 
set-aside amount for each control period of 5 percent of the state's 
emissions budget, with no additional consideration for planned units, 
because this approach is consistent with New York's preferences as 
reflected in an approved SIP addressing allowance allocations for the 
Group 2 trading program. Because the amounts of the state emissions 
budgets for the 2023 and 2024 control periods would be determined in 
the rulemaking, the amounts of the new unit set-asides for these 
control periods would also be determined in the rulemaking. The 
proposed amounts are shown in Tables VII.B.9.a-1 and VII.B.9.a-2 of 
this proposed rule.

    Table VII.B.9.a-1--Proposed CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for the 2023
                                               Control Period \a\
----------------------------------------------------------------------------------------------------------------
                                                                                   New unit set-   New unit set-
                              State                                  Emissions     aside amount    aside amount
                                                                  budgets (tons)     (percent)        (tons)
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................           6,364               3             191
Arkansas........................................................           8,889               2             178
Delaware........................................................             384              14              54
Illinois........................................................           7,364               5             368
Indiana.........................................................          11,151               2             223
Kentucky........................................................          11,640               2             233
Louisiana.......................................................           9,312               2             186
Maryland........................................................           1,187               2              24
Michigan........................................................          10,718               4             429
Minnesota.......................................................           3,921               2              78
Mississippi.....................................................           5,024               2             100
Missouri........................................................          11,857               2             237
Nevada..........................................................           2,280               6             137
New Jersey......................................................             799               2              16
New York........................................................           3,763               5             188
Ohio............................................................           8,369               5             418
Oklahoma........................................................          10,265               2             205
Pennsylvania....................................................           8,855               3             266
Tennessee.......................................................           4,234               2              85
Texas...........................................................          38,284               2             766
Utah............................................................          14,981               3             449
Virginia........................................................           3,090               5             155
West Virginia...................................................          12,478               2             250
Wisconsin.......................................................           5,963               2             119
Wyoming.........................................................           9,125               3             274
----------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ In the event a final rule in this rulemaking becomes effective after May 1, 2023, the emissions budgets for
  the 2023 control period would be adjusted under the rule's proposed transitional provisions to ensure the new
  budgets would apply only after the rule's effective date, even though the revised Group 3 trading program
  would be implemented for most sources as of the start of the 2023 ozone season on May 1, 2023. The 2023 budget
  amounts shown in Table VII.B.9.a-1 do not reflect these possible adjustments. The transitional provisions are
  discussed in Section VII.B.11 of this proposed rule.


[[Page 20128]]


    Table VII.B.9.a-2--Proposed CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for the 2024
                                                 Control Period
----------------------------------------------------------------------------------------------------------------
                                                                                   New unit set-   New unit set-
                              State                                  Emissions     aside amount    aside amount
                                                                  budgets (tons)     (percent)        (tons)
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................           6,306               3             189
Arkansas........................................................           8,889               2             178
Delaware........................................................             434              14              61
Illinois........................................................           7,463               5             373
Indiana.........................................................           9,391               2             188
Kentucky........................................................          11,640               2             233
Louisiana.......................................................           9,312               2             186
Maryland........................................................           1,187               2              24
Michigan........................................................          10,718               4             429
Minnesota.......................................................           3,921               2              78
Mississippi.....................................................           4,400               2              88
Missouri........................................................          11,857               2             237
Nevada..........................................................           2,372               6             142
New Jersey......................................................             799               2              16
New York........................................................           3,763               5             188
Ohio............................................................           8,369               5             418
Oklahoma........................................................           9,573               2             191
Pennsylvania....................................................           8,855               3             266
Tennessee.......................................................           4,234               2              85
Texas...........................................................          38,284               2             766
Utah............................................................          15,146               3             454
Virginia........................................................           2,814               5             141
West Virginia...................................................          12,478               2             250
Wisconsin.......................................................           5,057               2             101
Wyoming.........................................................           8,573               3             257
----------------------------------------------------------------------------------------------------------------

    For control periods in 2025 and later years, the EPA proposes to 
allocate a total of 2% of each state emissions budget to a new unit 
set-aside, with no additional amount for planned new units. The amounts 
of the set-asides for each state and control period would be computed 
when the emissions budgets for the control period are established, by 
May 1 of the year before the year of the control period. The procedure 
for determining the amounts of the set-asides based on the amounts of 
the state emissions budgets would be codified in the Group 3 trading 
program regulations and would reflect the same percentage of the 
emissions budget for all states.
    The purpose of the proposed change to the procedure for 
establishing the amounts of the set-asides is to coordinate with the 
dynamic budget-setting process that would also become effective as of 
the 2025 control period. As discussed in Section VII.B.4 of this 
proposed rule, under the dynamic budget-setting process, each state's 
budget for each control period would be computed using fleet 
composition information and the total ozone season heat input reported 
by all affected units in the state for the latest control period before 
the budget-setting computations, which would be 2 years before the 
control period for which the budgets are being determined. (For 
example, 2025 emissions budgets would be based on 2023 fleet 
composition and heat input data.) Moreover, as discussed in Section 
VII.B.9.b of this proposed rule, all units whose heat input was used in 
the budget computations for a given control period would be eligible to 
receive allocations as ``existing'' units in that control period. 
Consequently, by the 2025 control period, all or almost all units that 
commence commercial operation before issuance of a final rule in this 
rulemaking would be considered ``existing'' units for purposes of 
budget-setting and allocations, and units commencing commercial 
operation after issuance of a final rule generally would be considered 
``existing'' units for all but their first two full control periods of 
operation (and possibly a preceding partial control period). Given that 
new units would not be relying on the new unit set-asides as a 
permanent source of allowances, as is the case for ``new'' units under 
the other CSAPR trading programs, the EPA believes smaller set-asides 
would be sufficient.
    The EPA requests comment on the proposals to establish Indian 
country existing unit set-asides, eliminate Indian country new unit 
set-asides, and expand eligibility for allocations from new unit set-
asides to include units in Indian country for control periods in 2023 
and later years. In the alternative, the EPA requests comment on 
establishing emissions budgets (and assurance levels and new unit set-
asides) for the Uintah and Ouray Reservation separate from the 
emissions budgets (and assurance levels, new unit set-asides, and 
Indian country new unit set-asides) established for the remaining lands 
within Utah's borders, and otherwise retaining the structure of prior 
CSAPR trading programs' approach to allocations to new units in Indian 
country (i.e., keeping the Indian country new unit set-asides, and not 
expanding eligibility for allocations from the new unit set-asides). 
The EPA also requests comment on the proposed new unit set-aside 
amounts for the 2023 and 2024 control periods, the proposed procedure 
for establishing the new unit set-aside amounts for the control periods 
in 2025 and later years, and the proposed procedure for establishing 
the Indian country existing unit set-aside amounts for the control 
periods in 2023 and later years.
b. Allocations to Existing Units, Including Units That Cease Operation
    In conjunction with the new and revised state emissions budgets for 
the Group 3 trading program proposed in this rulemaking, the EPA is 
necessarily proposing new unit-level allocations of Group 3 allowances 
to existing units.\287\

[[Page 20129]]

The procedure that the EPA proposes to employ to compute the unit-level 
allocations is very similar but not identical to the procedure used to 
compute unit-level allocations for units subject to the Group 3 trading 
program in the Revised CSAPR Update. The steps of the proposed 
procedure for determining allocations from each state emissions budget 
for each control period, are described in detail in the Unit-Level 
Allowance Allocations Proposed Rule TSD. The steps are summarized 
later, with changes from the procedure followed in the Revised CSAPR 
Update noted.
---------------------------------------------------------------------------

    \287\ The proposed revisions to the procedures for computing 
unit-level allowance allocations in this rulemaking apply only to 
the Group 3 trading program. In this rulemaking, the EPA is not 
proposing changes to or reopening the methodology for computing the 
amounts of allowances allocated to any unit under any other CSAPR 
trading program.
---------------------------------------------------------------------------

    In the first step, the EPA would identify the list of units 
eligible to receive allocations for the control period, which would be 
the same set of units whose heat input was used in computing the 
state's emissions budget for the control period (except any units that 
are included in the budgets as ``new'' units, which would receive 
allocations from the new unit set-asides instead). The unit inventories 
used to compute emissions budgets for the 2023 and 2024 control periods 
would be determined in the rulemaking in the same manner as in the 
Revised CSAPR Update. The unit inventories used to compute emissions 
budgets and unit-level allocations for control periods in 2025 and 
later years would be determined in the year before the control period 
in question based on the latest reported emissions and operational 
data, which is an extension of the methodology used in the Revised 
CSAPR Update to reflect more recent data (for example, the unit 
inventories used to compute 2025 budgets and allocations would reflect 
reported data for the 2023 control period). The procedures for updating 
the unit inventories for 2023 and 2024 and for 2025 and beyond are 
discussed in Section VII.B.4 of this proposed rule, and the criteria 
that the EPA has applied to determine whether a unit's scheduled 
retirement is sufficiently certain to serve as a basis for adjusting 
emissions budgets and unit-level allocations are discussed in Section 
VI.B and in the Ozone Transport Policy Analysis Proposed Rule TSD. With 
regard to the use of the inventories from the budget-setting procedure 
in setting unit-level allocations, in the Revised CSAPR Update, the 
inventories used to establish the budgets were generally also used to 
compute unit-level allocations, except that units that commenced 
construction after January 1, 2019, were not treated as eligible to 
receive allocations as existing units and instead received allocations 
from the new unit set-asides. Under this rulemaking, any unit whose 
heat input is used to set a state's emissions budget for a given 
control period would also be eligible to receive allocations as an 
existing unit for that control period.
    The EPA notes that this proposal to base the list of eligible units 
on the list of units that reported heat input in the control period 2 
years earlier than the control period for which allocations are being 
determined would represent a revision to the current regulations 
concerning the treatment of allocations to retired units. Under the 
current regulations, units that cease operations for 2 consecutive 
control periods continue to receive allocations as existing units for 3 
additional years (that is, a total of 5 years) before the allowances 
they would otherwise have received are reallocated to the new unit set-
aside for the state. Under the proposal in this rulemaking, units that 
cease operation would receive allocations for only two full control 
periods of non-operation. While the EPA has in prior transport 
rulemakings noted a qualitative concern that ceasing allowance 
allocations prematurely could distort the economic incentives of EGUs 
to continue operating when retirement is more economical, the EPA 
believes current market conditions are such that a continuation of 
allowance allocations to retiring units likely has no more than a de 
minimis effect on the consideration of an EGU whether to retire or not.
    In the second step of the procedure for determining allocations to 
existing units, the EPA would compile a database containing for each 
eligible unit the unit's historical heat input and total NOX 
emissions data for the five most recent ozone seasons. For each unit, 
the EPA would compute an average heat input value based on the three 
highest non-zero heat input values over the 5-year period, or as the 
average of all the non-zero values in the period if there are fewer 
than three non-zero values. For each unit, the EPA would also determine 
the maximum total NOX emissions value over the 5-year 
period. These procedures are nearly identical to the procedures used in 
the Revised CSAPR Update, with two exceptions. First, instead of using 
only the data available at the time of the rulemaking, for each control 
period the EPA would use data from the most recent five control periods 
for which data had been reported. (For example, for the 2025 control 
period, the EPA would use data for the 2019-2023 control periods.) 
Second, to simplify the data compilation process, the EPA would use 
only a five-year period for NOX mass emissions, in contrast 
to the 8-year period used in the Revised CSAPR Update for 
NOX mass emissions.
    In the third step of the procedure for determining allocations to 
existing units in each state, the EPA would allocate the available 
allowances for that state among the state's eligible units in 
proportion to the share each unit's average heat input value represents 
of the total of the average heat input values for all the state's 
eligible units, but not more than the unit's maximum total 
NOX value. If the allocations to one or more units are 
curtailed because of the units' maximum total NOX values, 
the EPA would iterate the calculation procedure as needed to allocate 
the remaining allowances, excluding from each successive iteration any 
units whose allocations have already reached their maximum total 
NOX values. This calculation procedure is identical to the 
calculation procedure used in the Revised CSAPR Update (as well as the 
CSAPR Update and CSAPR).
    The unit-level allocations for the 2023 and the 2024 control 
periods would be determined in the rulemaking based on the emissions 
budgets for those control periods also determined in the rulemaking and 
would be recorded 30 days after the effective date of the final rule 
(in order to provide time to execute the proposed recall of 2023 and 
2024 Group 2 allowances, as discussed in Section VII.B.11.c of this 
proposed rule). This proposed recordation schedule represents a 
revision to the recordation schedule currently in the Group 3 trading 
program regulations which calls for allocations of 2023 and 2024 Group 
3 allowances to existing units to be recorded on July 1, 2022. The EPA 
notes that for the three states with approved SIP revisions 
establishing their own methodologies for allocating Group 2 
allowances--Alabama, Indiana, and New York--EPA proposes to follow 
those methodologies to the extent possible in developing the 
allocations of Group 3 allowances for the 2023 and 2024 control 
periods. For the amounts of the proposed allocations to existing units 
for the 2023 and 2024 control periods, see the ``Unit-Level Allowance 
Allocations Proposed Rule TSD'' in the docket.
    The unit-level allocations for each control period in 2025 or a 
later year would be computed immediately following the determination of 
the emissions budgets for the control period. The EPA would perform the

[[Page 20130]]

computations and issue a notice of data availability concerning the 
preliminary unit-level allocations for each control period by March 1 
of the year before the control period. Objections to the data and 
preliminary computations could be submitted for 30 days, and the EPA 
would make any appropriate revisions and issue another notice of data 
availability by May 1 of the year before the control period. The EPA 
would then record the allocations by July 1 of the year before the 
control period. This proposed recordation schedule--which is 
necessitated by the fact that the amounts of the unit-level allocations 
to be recorded would not be known until the year before the control 
period, as just discussed--represents a revision to the recordation 
schedule currently in the Group 3 trading program regulations which 
calls for allocations of Group 3 allowances to existing units for 
control periods in 2025 and later years to be recorded on July 1 of the 
third year before the year of the control period. The EPA does not 
propose to follow any state-specific methodologies as part of the 
procedures for determining default unit-level allocations of Group 3 
allowances for control periods in 2025 or later years, but any state 
wishing to use a procedure different than EPA's default allocations 
procedure could do so by obtaining approval of a SIP revision, as 
discussed in Section VII.D of this proposed rule.
    In the case of any states making state-determined allocations under 
approved SIP revisions, the allocations would have to be submitted to 
EPA by June 1 of the year before the control period and the EPA would 
record the allocations by July 1 of the year before the control period. 
The proposed submission deadline would represent a revision of the 
current deadline of June 1 of the year 3 years before the control 
period, and the proposed recordation deadline would represent a 
revision of the current deadline of July 1 of the year 3 years before 
the control period. The purpose of revising the submission deadline is 
to provide each state for which the EPA has approved a SIP revision 
authorizing state-determined allowance allocations a period of time in 
which to apply the state's preferred allocation methodology to the 
state's trading budget for the appropriate control period. Because the 
state trading budgets under the Group 3 trading program as revised 
would not be known until May 1 of the year before each control period, 
states could not determine unit-level allocations of the budgets using 
their own methodologies significantly before June 1 of the year before 
the control period. Submission by June 1 would allow the allowance 
allocations to the units in the state to be recorded by July 1 of the 
year before the control period, simultaneously with the recordation of 
allocations to units in states where the EPA determines the 
allocations.
    As an exception to all of the recordation deadlines that would 
otherwise apply, the EPA proposes to not record any allocations of 
Group 3 allowances in a source's compliance account unless that source 
has complied with the requirements to surrender previously allocated 
2023-2024 Group 2 allowances. The surrender requirements are necessary 
to maintain the previously established levels of stringency of the 
Group 2 trading program for the states and sources that remain subject 
to that program under this final rule. The EPA finds that it is 
reasonable to condition the recordation of Group 3 allowances on 
compliance with the surrender requirements because the condition will 
spur compliance and will not impose an inappropriate burden on sources. 
The EPA considers establishment of this condition, which will 
facilitate the continued functioning of the Group 2 trading program, to 
be an appropriate exercise of the Agency's authority under CAA section 
301 (42 U.S.C. 7601) to prescribe such regulations as are necessary to 
carry out its functions under the Act.
    The EPA requests comment on the proposed revisions to the 
procedures for allocating allowances to existing units under the Group 
3 trading program, the deadlines for recording the allocations, and the 
deadlines for submission of state-determined allowance allocations to 
the EPA.
c. Allocations From Portions of State Emissions Budgets Set Aside for 
New Units
    As promulgated in the Revised CSAPR Update, the Group 3 trading 
program regulations provide for the EPA to allocate allowances from 
each new unit set-aside and Indian country new unit set-aside after the 
end of the control period at issue. The regulations call for the EPA to 
allocate allowances to any eligible ``new'' units in the state in 
proportion to their respective emissions during the control period, up 
to the amounts of those emissions if the relevant set-aside contains 
sufficient allowances, and not exceeding those emissions. An eligible 
new unit for purposes of allocations from a set-aside for a given 
control period is generally any unit in the relevant area that reported 
emissions subject to allowance surrender requirements during the 
control period and that was not eligible to receive an allowance 
allocation as an ``existing'' unit for the control period. Any 
allowances remaining in an Indian country new unit set-aside after the 
allocations to new units are transferred to the new unit set-aside for 
the state for potential allocation to new units in non-Indian country 
areas of the state, and any allowances remaining in a new unit set-
aside after the allocations to new units are reallocated to the 
existing units in the state in proportion to those units' previous 
allocations for the control period as existing units. The EPA issues a 
notice of data availability concerning the proposed allocations by 
March 1 following the control period, provides an opportunity for 
submission of objections, and issues a final notice of data 
availability and record the allocations by May 1 following the control 
period, one month before the June 1 compliance deadline.
    In this rulemaking, as discussed in Section VII.B.9.a of this 
document, the EPA is proposing to eliminate Indian country new unit 
set-asides after the 2022 control period and to expand eligibility for 
allocations from each state's new unit set-aside for a control period 
in 2023 or a later year to include units in Indian country within the 
state's borders, regardless of whether the area of Indian country is 
covered by the state's CAA implementation planning authority. The 
reasons for these proposed revisions are discussed in Section VII.B.9.a 
of this proposed rule. The EPA is not proposing any substantive 
revisions to the current Group 3 trading program provisions governing 
the procedures for allocating allowances from a state's new unit set-
aside for a control period to the eligible units within the state's 
borders.\288\
---------------------------------------------------------------------------

    \288\ As discussed in Section X of this proposed rule, the EPA 
is proposing to relocate some of the regulatory provisions relating 
to administration of the new unit set-asides and is also proposing 
to remove certain provisions that would be made obsolete by proposed 
revisions to other provisions of the Group 3 trading program 
regulations.
---------------------------------------------------------------------------

    This EPA notes that the proposed revisions to other provisions of 
the Group 3 trading program regulations discussed elsewhere in this 
document will reduce the portions of the state emissions budgets that 
are allocated through the new unit set-asides. Specifically, because 
the new unit set-asides will no longer receive any additional 
allowances when units retire, for control periods in 2025 and later 
years the amounts of allowances in the new unit set-asides will always 
be 2 percent of the respective state emissions budgets for the 
respective control periods. This reduction in the size of the

[[Page 20131]]

new unit set-asides is appropriate given that the number of consecutive 
control periods for which any particular unit is likely to receive 
allocations from a state's new unit set-aside will be reduced to two or 
three before the unit becomes eligible to receive allocations from the 
unreserved portion of the state's emissions budget. This approach 
contrasts with the approach under the other CSAPR trading programs 
where a new unit never becomes eligible to receive allocations from the 
unreserved portion of the emissions budget and where the new unit set-
aside therefore needs to grow to accommodate an ever-increasing share 
of the state's total emissions.
    The EPA also notes that, as discussed in Sections VII.D.2 and 
VII.D.3 of this proposed rule, in the event that a state chooses to 
replace EPA's default allowance allocations under the Group 3 trading 
program with state-determined allocations through a SIP revision, the 
EPA will continue to administer the portion of each state emissions 
budget reserved in a new unit set-aside in order to ensure the 
availability of allowance allocations to new units in any areas of 
Indian country within the state not covered by the state's CAA 
implementation planning authority.
d. Incorrectly Allocated Allowances
    The Group 3 trading program regulations as promulgated in the 
Revised CSAPR Update include provisions addressing incorrectly 
allocated allowances. With regard to any allowances that were 
incorrectly allocated and are subsequently recovered, the current 
provisions generally call for the recovered allowances to be 
reallocated to other units in the relevant state (or Indian country 
within the borders of the state) through the process for allocating 
allowances from the new unit set-aside (or Indian country new unit set-
aside) for the state. If the procedures for allocating allowances from 
the set-asides have already been carried out for the control period for 
which the recovered allowances were issued, the allowances would be 
allocated through the set-asides for subsequent control periods.
    The EPA continues to view the current provisions for disposition of 
recovered allowances as reasonable in the case of any allowances that 
are recovered before the deadline for recording allocations of 
allowances from the new unit set-aside for the control period for which 
the recovered allowances were issued. However, in the case of any 
allowances that are recovered after that deadline, adding the recovered 
allowances to the new unit set-aside for a subsequent control period, 
as provided in the current regulations, would be inconsistent with the 
proposed trading program enhancements discussed elsewhere in this 
document, where the amounts of allowances provided in the state 
emissions budgets for each control period are designed to reflect the 
most current available information on fleet composition and utilization 
and where the quantities of banked allowances available for use in each 
control period are recalibrated for consistency with the state 
emissions budgets. The EPA therefore proposes that, starting with 
allowances allocated for the 2024 control period, any incorrectly 
allocated allowances that are recovered after the deadline for 
allocating allowances from the new unit set-aside for that control 
period (i.e., May 1 of the year following the control period) would be 
transferred to a surrender account instead of being reallocated to 
other units in the state.
    The EPA requests comment on the proposed revision to the provisions 
for disposition of incorrectly allocated allowances that are recovered 
after the deadline for allocating allowances from the new unit set-
asides for the control periods for which the recovered allowances were 
issued.
10. Other Trading Program Provisions
    This section discusses how certain existing provisions of the Group 
3 trading program regulations would apply to sources that become 
subject to the program as a result of a final rule in this rulemaking 
as well as certain proposed changes to reporting requirements 
associated with the proposed backstop daily NOX emissions 
rates for coal-fired units.
a. Designated Representative Requirements
    As noted in Section VII.B.1.a of this document, a core design 
element of all the CSAPR trading programs is the requirement that each 
source must have a designated representative who is authorized to 
represent all of the source's owners and operators and is responsible 
for certifying the accuracy of the source's reports to the EPA and 
overseeing the source's Allowance Management System account. The 
necessary authorization of a designated representative is certified to 
the EPA in a certificate of representation. The EPA is not proposing 
any change to the Group 3 trading program's designated representative 
provisions in this rulemaking.
    The existing designated representative provisions in the Group 3 
trading program regulations already provide that EPA will interpret 
references to the Group 2 trading program in certain documents--
including a certificate of representation as well as a notice of 
delegation to an agent or an application for a general account--as if 
the documents referenced the Group 3 trading program instead of the 
Group 2 trading program. For these reasons, sources that currently 
participate in the Group 2 trading program and that transition to the 
Group 3 trading program because of a final rule in this rulemaking will 
not need to submit any new forms as part of the transition, because 
previously submitted forms will be valid for purposes of the Group 3 
trading program.
    Designated representatives for sources that are newly affected 
under the Group 3 trading program and that are not currently affected 
under the Group 2 trading program would need to submit new or updated 
certificates of representation. If the source is also affected under 
other CSAPR trading programs or the Acid Rain Program, the source's 
designated representative for all of the programs must be the same 
individual. The EPA will not record any Group 3 allowances allocated to 
a source in the source's compliance account until the source has a 
properly authorized designated representative.
b. Monitoring and Reporting Requirements
    The Group 3 trading program requires monitoring and reporting of 
emissions and heat input data in accordance with the provisions of 40 
CFR part 75. In this rulemaking, the EPA is not proposing any change to 
these provisions of the Group 3 trading program except with respect to 
the monitor certification deadline for certain units. The EPA is also 
not proposing any changes to the monitoring requirements in 40 CFR part 
75 for units subject to such requirements. However, because of the 
proposed geographic expansion of the Group 3 trading program, certain 
units that were not previously subject to monitoring requirements under 
40 CFR part 75 would become subject to such requirements. Also, the EPA 
is proposing certain additional recordkeeping and reporting 
requirements that would be met using some of the data that are already 
collected by the required monitoring systems.\289\
---------------------------------------------------------------------------

    \289\ The EPA is not proposing to amend the existing provisions 
of the Group 3 trading program regulations that govern whether units 
covered by the program must record and report required data on a 
year-round basis or may elect to record and report required data on 
an ozone season-only basis. See 40 CFR 97.1034(d)(1); see also 40 
CFR 75.74(a)-(b). Thus, for units that are required or elect to 
report other data on a year-round basis, the proposed additional 
recordkeeping and reporting requirements would also apply year-
round, while for units that are allowed and elect to report other 
data on an ozone season-only basis, the proposed additional 
requirements would also apply for the ozone season only.

---------------------------------------------------------------------------

[[Page 20132]]

    Under 40 CFR part 75, a unit has several options for monitoring and 
reporting, including the use of continuous emissions monitoring systems 
(CEMS), excepted monitoring methodologies for qualifying gas- or oil-
fired units that rely in part on fuel-flow metering in combination with 
CEMS-based or testing-based NOX emissions rate data, low-
mass emissions monitoring for certain non-coal-fired, low emitting 
units, and alternative monitoring systems approved by the Administrator 
through a petition process. In addition, sources can submit petitions 
to the Administrator for alternatives to individual monitoring, 
recordkeeping, and reporting requirements specified in 40 CFR part 75. 
Each CEMS must undergo rigorous initial certification testing and 
periodic quality assurance testing thereafter, including the use of 
relative accuracy test audits and 24-hour calibrations. In addition, 
when a monitoring system is not operating properly, standard substitute 
data procedures are applied to produce a conservative estimate of 
emissions for the period involved. Further, 40 CFR part 75 requires 
electronic submission of quarterly emissions reports to the 
Administrator, in a format prescribed by the Administrator. The reports 
would contain all of the data required concerning ozone season 
NOX emissions.
    For units exhausting to common stacks, 40 CFR part 75 includes 
options that often allow monitoring to be conducted at the common stack 
on a combined basis for all the units as an alternative to installing 
separate monitoring systems for the individual units in the ductwork 
leading to the common stack. The units then keep records and report 
hourly and cumulative NOX mass emissions and in many cases 
heat input data on a combined basis for all units exhausting to the 
common stack. With respect to heat input data, but not NOX 
mass emissions data, most such units are also required to record and 
report hourly and cumulative data on an individual-unit basis, and 
where necessary they typically compute the necessary unit-level hourly 
heat input values by apportioning the combined hourly heat input values 
for the common stack in proportion to the individual units' recorded 
hourly output of electricity or steam. See generally 40 CFR 75.72.
    In this rulemaking, the proposed provisions governing default unit-
level allowance allocations, backstop daily NOX emissions 
rates for certain coal-fired units, and secondary emissions limitations 
for units contributing to assurance level exceedances would all require 
the use of unit-level reported data on NOX mass emissions 
(or unit-level NOX emissions rates computed in part based on 
unit-level reported data on NOX mass emissions). To 
facilitate the implementation of these proposed provisions, the EPA is 
proposing to require all units covered by the Group 3 trading program 
exhausting to common stacks to record and report unit-level hourly and 
cumulative NOX mass emissions data starting with the 2024 
control period. To obtain the necessary unit-level hourly mass 
emissions values, the EPA proposes to allow the units to apportion 
hourly mass emissions values determined at the common stack in 
proportion to the individual units' recorded hourly heat input. The 
proposed apportionment procedure would be very similar to the 
apportionment procedure that most such units already apply to compute 
reported unit-level heat input data. Because the additional required 
data values would be obtained through apportionment, implementation of 
the proposed additional recordkeeping and reporting requirements would 
necessitate a one-time update to the units' data acquisition and 
handling systems but would not require any changes to the monitoring 
systems already needed to meet other requirements under 40 CFR part 75. 
In most cases, the EPA expects that the reported values computed 
through these apportionment procedures would reasonably approximate the 
values that could be obtained through installation and operation of 
separate monitoring systems for the individual units, because the units 
exhausting to the common stack would be expected to have similar 
NOX emissions rates. However, the EPA also recognizes that 
at some plants, unit-level values determined through apportionment 
based on electricity or steam output could overstate the reported 
NOX mass emissions for some units and correspondingly 
understate the reported NOX mass emissions for other units. 
While the EPA has not at this time identified any reason to expect such 
potential overstatement and understatement to cause the proposed 
requirements in this rule to be less stringent overall, the Agency 
requests comment on whether units in particular situations should be 
required to obtain the necessary hourly mass emissions values through 
installation and operation of monitoring systems at the individual-unit 
level.\290\
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    \290\ For example, as noted in Section VII.B.7 of this proposed 
rule, there are currently five plants in the states covered by this 
proposal where SCR-equipped coal-fired units and non-SCR-equipped 
coal-fired units exhaust to common stacks. If the owners and 
operators of these plants choose to report apportioned 
NOX mass emissions data in preference to installing and 
operating separate monitoring systems, the likely effect would be to 
overstate reported NOX mass emissions for the SCR-
equipped units and correspondingly understate reported 
NOX mass emissions for the non-SCR equipped units. This 
would make compliance with the proposed backstop daily 
NOX emissions rate more challenging for the SCR-equipped 
units. If the EPA does not require the owners and operators to 
install and operate separate monitoring systems for the individual 
units in a final rule in this rulemaking, the owners and operators 
would still have the option to do so if they believed it would be to 
their benefit.
---------------------------------------------------------------------------

    In addition, to implement the proposed backstop daily 
NOX emissions rates during the ozone season for certain 
coal-fired units, the EPA is proposing to require additional 
recordkeeping and reporting requirements for these units. Specifically, 
starting in 2024 for coal-fired units with existing SCR controls 
serving generators larger than 100 MW, and starting in 2027 for other 
coal-fired units serving generators larger than 100 MW (except 
circulating fluidized bed units), the units would be required to record 
and report total daily NOX emissions and total daily heat 
input, daily average NOX emissions rate, and daily 
NOX emissions exceeding the applicable backstop daily 
NOX emissions rates. The units would also be required to 
record and report cumulative NOX emissions exceeding the 
backstop daily NOX emissions rates for the ozone season. 
These data would be used to determine the allowance surrender 
requirements related to the backstop daily NOX emissions 
rates. As with the additional recordkeeping and reporting requirements 
discussed above for units exhausting to common stacks, implementation 
of the additional recordkeeping and reporting requirements for coal-
fired units would necessitate a one-time update to the units' data 
acquisition and handling systems but would not require any changes to 
the monitoring systems already needed to meet other requirements under 
40 CFR part 75.
    In states whose sources currently participate in the Group 3 
trading program, as well as states whose sources participate in the 
Group 2 trading program and would transition to the

[[Page 20133]]

Group 3 trading program under this proposal, units that are not subject 
to the proposed backstop daily NOX emissions rates would not 
need to make any changes to their current monitoring and reporting as a 
result of the transition. The sources in states currently in the Group 
2 trading program would be required to begin monitoring and reporting 
of NOX emissions and operational data for purposes of the 
Group 3 trading program as of May 1, 2023, the start of the 2023 
control period.
    In states whose sources do not currently participate in the Group 2 
trading program, any sources that currently report ozone season 
NOX mass emissions according to 40 CFR part 75 to comply 
with SIP requirements and that are not subject to the proposed backstop 
daily NOX emissions rates similarly would not need to make 
any changes to their current monitoring and reporting as a result of 
the transition. Other sources in these states that currently report 
SO2 and NOX emissions data according to 40 CFR 
part 75 under other CSAPR trading programs or the Acid Rain Program 
would not need to certify new monitoring systems for purposes of the 
Group 3 trading program but would need to update their monitoring plans 
and possibly update the software in their data acquisition and handling 
systems to compute certain additional values from the measurements that 
are already being recorded. All the sources in these states that 
already have monitoring systems certified under 40 CFR part 75 would be 
required to begin monitoring and reporting of NOX emissions 
and operational data for purposes of the Group 3 trading program as of 
the later of May 1, 2023, or the effective date of the final rule.\291\
---------------------------------------------------------------------------

    \291\ For units that currently report under 40 CFR part 75 only 
for annual programs and that use the optional low mass emissions 
methodology in 40 CFR 75.19, an additional consideration could 
arise. Specifically, eligibility to use the low mass emissions 
methodology for reporting ozone season NOX mass emissions 
is restricted to units demonstrating that they have not exceeded or 
will not exceed a maximum of 50 tons of NOX per ozone 
season. In theory, some units that would be eligible to use the low 
mass emissions methodology for purposes of annual programs only 
might lose that eligibility because of the 50-ton ozone season cap 
(which does not apply to units reporting for annual programs only). 
Based on the emissions reports submitted for the 2018-2020 control 
periods under the Acid Rain Program and the CSAPR annual programs, 
none of the existing units that currently report under 40 CFR part 
75 for annual programs only and that would be added to the Group 3 
trading program under the proposal are presently in this theoretical 
situation.
---------------------------------------------------------------------------

    Finally, any sources that meet the applicability criteria of the 
Group 3 trading program and that do not currently report NOX 
emissions data to the EPA under 40 CFR part 75 would need to certify 
new monitoring systems in accordance with part 75 before they would be 
required to monitor and report emissions for purposes of the Group 3 
trading program. The units the EPA has been able to identify as 
potentially affected under this proposal that may need to certify new 
monitoring systems are listed in Table VII.B.3-1 (along with some other 
units that are potentially affected under this proposal and that 
already have certified monitoring systems). Because each of the listed 
units commenced commercial operation more than 180 days before the date 
when a final rule in this rulemaking would become effective, under the 
current Group 3 trading program regulations (i.e., without the 
revisions proposed in this section), each unit's monitor certification 
deadline would generally be the effective date of the final rule. To 
ensure that the final rule does not impose monitor installation and 
certification requirements on these units before the effective date of 
the final rule, the EPA is proposing to revise the Group 3 trading 
program's monitor certification deadline provisions to establish a 180-
day window for certification of the new monitoring systems after the 
effective date of a final rule in this rulemaking for units that do not 
already have monitoring systems certified under 40 CFR part 75, similar 
to the 180-day window already provided to units commencing commercial 
operation after (or less than 180 days before) the final rule's 
effective date. The 180th day for units in this situation would likely 
fall after the end of the 2023 ozone season, with the result that the 
certification deadline would be extended until May 1, 2024, the first 
day of the 2024 ozone season. Because the program's allowance holding 
requirements apply to a given unit only after that unit's monitor 
certification deadline, the units in this situation consequently would 
become subject to allowance holding requirements as of the 2024 ozone 
season rather than the 2023 ozone season.\292\
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    \292\ Table VII.B.3-1 of this proposed rule lists 22 existing 
units in Delaware, Nevada, Utah, and Wyoming that appear to meet the 
Group 3 trading program's general applicability criteria and that do 
not already report NOX emissions data to the EPA under 40 
CFR part 75 pursuant to any other existing regulatory requirements. 
As noted in Section VII.B.3 of this proposed rule, six of the 22 
listed units have reported that they may retire before the 2023 
ozone season, and the possibility exists that up to nine of the 
remaining listed units could qualify for an exemption from the Group 
3 trading program available to certain cogeneration units. EPA 
therefore projects that the revision to the monitor certification 
deadline proposed in this section, and the related delay in 
allowance holding requirements from 2023 to 2024, could apply to 
between seven and 22 units, with the total estimated 2021 ozone 
season NOX emissions for all such units ranging between 
250 and 450 tons. During the period before allowance holding 
requirements apply to the units--i.e., the period from the effective 
date of a final rule in this rulemaking until the start of the 2024 
control period--other requirements of the program would still apply, 
such as the requirement for submission of a certificate of 
representation by a designated representative and the requirements 
related to installation and certification of required monitoring 
systems.
---------------------------------------------------------------------------

    The EPA requests comment on the proposed revisions to the 
recordkeeping and reporting provisions in 40 CFR part 75 and the 
proposed establishment of a 180-day window for certification of new 
monitoring systems after the effective date of a final rule in this 
rulemaking for units that do not already have monitoring systems 
certified under 40 CFR part 75. As discussed above, with respect to 
units exhausting to common stacks, the EPA also requests comment on 
whether units in particular situations should be required to obtain 
hourly NOX mass emissions values through installation and 
operation of monitoring systems at the individual-unit level instead of 
being allowed to obtain values for individual units through 
apportionment of the combined values for the units exhausting to the 
common stack.
11. Transitional Provisions
    This section discusses several provisions that the EPA proposes to 
implement in order to address the transition of sources into the Group 
3 trading program as revised. The purposes of the proposed transitional 
provisions are generally the same as the purposes of the analogous 
transitional provisions promulgated in the Revised CSAPR Update: First, 
accounting for the possibility that the effective date of a final rule 
in this rulemaking will fall after the starting date of the first 
affected ozone season (which in this case is, May 1, 2023); second, 
establishing an appropriately-sized initial allowance bank through the 
conversion of previously banked allowances; and third, preserving the 
intended stringency of the Group 2 trading program for the sources that 
will continue to be subject to that program.\293\ However, the sources 
that would be participants in the revised Group 3 trading program under 
this proposal are transitioning from several different starting 
points--with some sources already in the Group 3 trading

[[Page 20134]]

program under its current regulations, some sources coming from the 
Group 2 trading program, and some sources not currently participating 
in any seasonal NOX trading program. EPA is therefore 
proposing transitional provisions that differ across the sets of 
potentially affected sources based on the sources' different starting 
points.
---------------------------------------------------------------------------

    \293\ The EPA is not proposing to create a ``safety valve 
mechanism'' in this rulemaking analogous to the safety valve 
mechanism established under the Revised CSAPR Update.
---------------------------------------------------------------------------

a. Prorating Emissions Budgets, Assurance Levels, and Unit-Level 
Allowance Allocations in the Event of an Effective Date After May 1, 
2023
    While it is EPA's intent for a final rule in this rulemaking to 
take effect before the start of the Group 3 trading program's 2023 
control period on May 1, 2023, it is possible that the final rule's 
effective date will fall after that date. The EPA proposes to address 
this contingency by determining the amounts of emissions budgets and 
unit-level allowance allocations on a full-season basis in the 
rulemaking and by also including provisions in the revised regulations 
to prorate the full-season amounts as needed to ensure that no sources 
become subject to new or more stringent regulatory requirements before 
the final rule's effective date.\294\ Variability limits and assurance 
levels for 2023 would be computed using the appropriately prorated 
emissions budgets amounts, and unit-level allocations would also be 
prorated.\295\
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    \294\ As discussed in Sections VII.B.7 and VII.B.8 of this 
proposed rule, the proposed revisions establishing unit-specific 
backstop daily emissions rates and, for units contributing to 
assurance level exceedances, secondary unit-specific emissions 
limitations, would not take effect until the 2024 control period or 
later.
    \295\ The EPA notes that transitional provisions similar to the 
prorating provisions proposed in this section were finalized and 
implemented under the Revised CSAPR Update.
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    As discussed in Section VII.B.2 of this proposed rule, in the case 
of states (and Indian country within the states' borders) whose sources 
do not currently participate in either the Group 2 trading program or 
the Group 3 trading program--Delaware, Minnesota, Nevada, Utah, and 
Wyoming--the sources would begin participating in the Group 3 trading 
program on the later of May 1, 2023, or the final rule's effective 
date. For these states, in the rulemaking the EPA would compute the 
full-season emissions budgets that would apply for the entire 2023 
control period if the final rule becomes effective no later than May 1, 
2023, and is therefore in effect for the entire 153-day control period 
from May 1, 2023, through September 30, 2023. If the final rule becomes 
effective after May 1, 2023, the EPA would determine prorated emissions 
budgets by multiplying each full-season emissions budget by the number 
of days from the rule's effective date through September 30, 2023, 
dividing by 153 days, and rounding to the nearest allowance. The 
prorated variability limits would be computed as 21 percent of the 
prorated emissions budgets, rounded to the nearest allowance, yielding 
prorated assurance levels that equal 121 percent of the prorated 
emissions budgets. To determine unit-level allocation amounts from the 
prorated emissions budgets, the EPA would determine full-season 
allocation amounts in the rulemaking and would determine preliminary 
prorated allocation amounts in the same manner as described for the 
emissions budgets previously. The preliminary prorated amounts of the 
largest unit-level allowance allocations for each state would then each 
be adjusted up or down by one allowance as needed to cause the sum of 
the final prorated unit-level allowance allocations for the state to 
equal the state's prorated emissions budget. All calculations required 
to determine the prorated emissions budgets and variability limits and 
the unit-level allocations for the 2023 control period would be carried 
out as soon as possible after the EPA learns the effective date of a 
final rule in this rulemaking (which is expected to be approximately 60 
days after the date of the final rule's publication in the Federal 
Register). The unit-level allocations for both the 2023 and 2024 
control periods would be recorded in facilities' compliance accounts 
approximately 30 days after the final rule's effective date, as 
discussed in Section VII.B.9.b of this proposed rule.
    In the case of states (and Indian country within the states' 
borders) whose sources currently participate in the Group 3 trading 
program--Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia--
the sources would continue to participate in the Group 3 trading 
program for the 2023 control period, subject to prorating procedures 
designed to ensure that the changes in 2023 emissions budgets and 
assurance levels would not substantively affect the sources' 
requirements prior to the rule's effective date. For these states, in 
the rulemaking the EPA would compute the full-season emissions budgets 
that would apply for the entire 2023 control period if the final rule 
becomes effective no later than May 1, 2023, but the EPA would not 
remove from the regulations the full-season emissions budgets for the 
2023 control period that were established in the Revised CSAPR Update 
rulemaking. Instead, the EPA would include both sets of emissions 
budgets and variability limits in the regulations, along with a 
provision indicating that the emissions budgets promulgated in the 
Revised CSAPR Update would apply on a prorated basis for the portion of 
the 2023 control period before the final rule's effective date and the 
emissions budgets established in this rulemaking would apply on a 
prorated basis for the portion of the 2023 control period on and after 
the final rule's effective date. Under this provision, the EPA would 
determine a blended emissions budget for each state for the 2023 
control period, computed as the sum of the appropriately prorated 
amounts of the state's current and revised emissions budgets. (For 
example, if the final rule became effective on the eleventh day of the 
153-day 2023 control period, the blended emissions budget would equal 
the sum of 10/153 times the current emissions budget plus 143/153 times 
the revised emissions budget, rounded to the nearest allowance.) 
Blended variability limits for the 2023 control period would be 
computed as 21% of the blended emissions budgets, yielding blended 
assurance levels equal to 121 percent of the blended emissions budgets. 
Unit-level allocations would be determined by applying the allocation 
procedure described in Section VII.B.9 of this proposed rule to the 
blended budgets. In the case of states (and Indian country within the 
states' borders) whose sources currently participate in the Group 2 
trading program--Alabama, Arkansas, Mississippi, Missouri, Oklahoma, 
Tennessee, Texas, and Wisconsin--the sources would begin to participate 
in the Group 3 trading program as of May 1, 2023, regardless of the 
final rule's effective date, as discussed in Section VII.B.2 of this 
proposed rule, subject to prorating procedures designed to ensure that 
the transition from the Group 2 trading program to the Group 3 trading 
program would not substantively affect the sources' requirements prior 
to the rule's effective date. The prorating procedures for these states 
would mirror the procedures for the states currently in the Group 3 
trading program, except that because no emissions budgets currently 
appear in the Group 3 trading program regulations for the states that 
are currently covered by the Group 2 trading program, the EPA would add 
two sets of emissions budgets for these states to the Group 3 trading 
program regulations: First, the states' emissions budgets for the 2023 
control period that currently appear in the Group 2 trading

[[Page 20135]]

program regulations, which would be included in the revised Group 3 
trading program regulations to represent the states' emissions budgets 
for the portion of the 2023 control period before the final rule's 
effective date, and second, the emissions budgets for the 2023 control 
period established for the states in this rulemaking, which would be 
included in the revised Group 3 trading program regulations to 
represent the state's emissions budgets for the portion of the 2023 
control period on and after the final rule's effective date. The 
procedures for determining blended emissions budgets, variability 
limits and assurance levels, and unit-level allowance allocations would 
be the same as for the states currently in the Group 3 trading program. 
Again, all calculations required to determine the prorated emissions 
budgets and variability limits and the unit-level allocations for the 
2023 control period would be carried out as soon as possible after the 
EPA learns the effective date of a final rule in this rulemaking (which 
is expected to be approximately 60 days after the date of the final 
rule's publication in the Federal Register). The unit-level allocations 
for both the 2023 and 2024 control periods would be recorded in 
facilities' compliance accounts approximately 30 days after the final 
rule's effective date, as discussed in Section VII.B.9.b of this 
proposed rule.
    The reason for proposing that sources currently in the Group 2 
trading program would begin to participate in the Group 3 trading 
program on May 1, 2023 even if the final rule's effective date is after 
May 1, 2023, is that it would serve the public interest and greatly aid 
in administrative efficiency for most elements of the Group 3 trading 
program--specifically, all elements of the trading program other than 
the elements designed to establish more stringent emissions limitations 
for the sources coming from the Group 2 trading program--to apply to 
the sources starting on May 1, 2023. This would facilitate 
implementation of the Group 3 trading program in an orderly manner for 
the entire 2023 ozone season and reduce compliance burdens and 
potential confusion. Each of the CSAPR trading programs for ozone 
season NOX is designed to be implemented over an entire 
ozone season. Implementing the transition from the Group 2 trading 
program to the Group 3 trading program in a manner that required the 
covered sources to participate in the Group 2 trading program for part 
of the 2023 ozone season and the Group 3 trading program for the 
remainder of that ozone season would be complex and burdensome for 
sources. Attempting to address the issue by splitting the Group 2 and 
Group 3 requirements for these sources into separate years is not a 
viable approach, because EPA has no legal basis for releasing the 
transitioning Group 2 sources from the emissions reduction requirements 
found to be necessary in the CSAPR Update for a portion of the 2023 
ozone season, and EPA similarly has no legal basis for deferring 
implementation of the 2023 emissions reduction requirements found to be 
necessary under this rule for the transitioning Group 2 sources until 
2024. Moreover, the requirements of the current Group 2 trading program 
and the revised Group 3 trading program for the 2023 control period are 
substantively identical as to almost all provisions, such that with 
respect to those provisions, a source will not need to alter its 
operations in any manner or face different compliance obligations as a 
consequence of a transition from the Group 2 trading program to the 
Group 3 trading program. Thus, the EPA believes that no substantive 
concerns regarding retroactivity arise from transitioning the sources 
currently in the Group 2 trading program to the Group 3 trading program 
starting on May 1, 2023, as long as those aspects of the revised Group 
3 trading program for the 2023 control period that do meaningfully 
differ from the analogous aspects of the Group 2 trading program--that 
is, the relative stringencies of the two trading programs, as reflected 
in the emissions budgets and associated assurance levels--are applied 
only as of the effective date of the final rule.
    In all respects other than prorating the emissions budgets, 
variability limits and assurance levels, and unit-level allowance 
allocations, with respect to the sources currently participating in the 
Group 2 trading program or the Group 3 trading program, the EPA 
proposes to implement the revised Group 3 trading program for the 2023 
control period in a uniform manner for the entire control period. Thus, 
emissions would be monitored and reported for the entire 2023 ozone 
season (i.e., May 1, 2023, through September 30, 2023), and as of the 
allowance transfer deadline for the 2023 control period (i.e., June 1, 
2024) each source would be required to hold in its compliance account 
vintage-year 2023 Group 3 allowances not less than the source's 
emissions of NOX during the entire 2023 ozone season. Any 
efforts undertaken by one of these sources to reduce its emissions 
during the portion of the 2023 ozone season before the effective date 
of the rule would aid the source's compliance by reducing the amount of 
Group 3 allowances that the source would need to hold in its compliance 
account as of the allowance transfer deadline, increasing the range of 
options available to the source for meeting its compliance obligations 
under the revised Group 3 trading program. In the case of the sources 
that do not currently participate in the Group 2 trading program or the 
Group 3 trading program, the EPA similarly proposes to implement the 
revised Group 3 trading program for the 2023 control period in a 
uniform manner for the entire control period, except that the 2023 
control period for these sources may be shorter than the normal 153-day 
length.
    The EPA requests comment on this approach for implementing the 
Group 3 trading program in a manner that would apply the substantive 
increases in stringency of the emissions budgets and assurance levels 
established under the final rule on and after, but not before, the 
final rule's effective date.
b. Creation of Additional Group 3 Allowance Bank for 2023 Control 
Period
    In the CSAPR Update, where the EPA established the Group 2 trading 
program and transitioned over 95% of the sources that had been 
participating in what is now the CSAPR NOX Ozone Season 
Group 1 Trading Program (the ``Group 1 trading program'') to the new 
program, the EPA determined that it was reasonable to establish an 
initial bank of allowances for the Group 2 trading program by 
converting almost all allowances banked under the Group 1 trading 
program at a conversion ratio determined by a formula. In the Revised 
CSAPR Update, where EPA established the Group 3 trading program and 
transitioned approximately 55% of the sources that had been 
participating in the Group 2 trading program to the new program, the 
EPA similarly determined that it was reasonable to establish an initial 
bank of allowances for the Group 3 trading program by converting 
allowances banked under the Group 2 trading program at a conversion 
ratio determined by a formula, using a conversion procedure that was 
modified to leave much of the Group 2 allowance bank available for use 
by the approximately 45% of sources then in the Group 2 trading program 
that would remain in that program. Any conversion of banked allowances 
from a previous trading program for use in a new trading program must 
ensure that implementation of the new trading program will result in 
NOX emissions

[[Page 20136]]

reductions sufficient to address significant contribution by all states 
that would be participating in the new trading program, while also 
providing industry certainty (and obtaining an environmental benefit) 
through continued recognition of the value of saving allowances through 
early reductions in emissions. EPA's approach to balancing these 
concerns in the CSAPR Update through the conversion of banked 
allowances from the Group 1 trading program to the Group 2 trading 
program was upheld in Wisconsin v. EPA, see 938 F.3d at 321.
    In the current rulemaking, applying the same balancing principle as 
in the CSAPR Update and the Revised CSAPR Update, the EPA proposes to 
carry out a further conversion of allowances banked for control periods 
before 2023 under the Group 2 trading program into allowances usable in 
the Group 3 trading program in control periods in 2023 and later years. 
Because the EPA is proposing to transition over 90% of the remaining 
sources in the Group 2 trading program to the Group 3 trading program--
much closer to the situation in the CSAPR Update than the situation in 
the Revised CSAPR Update--in this rulemaking EPA proposes to apply a 
conversion procedure similar to the procedure followed in the CSAPR 
Update. Under the proposed conversion procedure, in the final rule in 
this rulemaking the EPA would not set a predetermined conversion ratio 
but instead would set provisions defining the types of accounts whose 
holdings of Group 2 allowances would be converted to Group 3 allowances 
and establishing the target amount of new Group 3 allowances that would 
be created. The proposed conversion date would be August 1, 2023, which 
is 2 months after the compliance deadline for the 2022 control period 
under the Group 2 trading program and ten months before the compliance 
deadline for the 2023 control period under the Group 3 trading program. 
The actual conversion ratio would be determined as of the conversion 
date and would be the ratio of the total amount of Group 2 allowances 
held in the identified types of accounts prior to the conversion to the 
total amount of Group 3 allowances being created. Consistent with the 
approach taken in the CSAPR Update, the EPA proposes to define the 
types of accounts included in the conversion to include all accounts 
except the facility accounts of sources in states that would remain in 
the Group 2 trading program.\296\ Thus, the accounts whose holdings of 
Group 2 allowances would be converted to Group 3 allowances would 
include (1) the facility accounts of all sources in the states 
transitioning from the Group 2 trading program to the Group 3 trading 
program, (2) the facility accounts of all sources in the states already 
participating in the Group 3 trading program, (3) the facility accounts 
of all sources in any other states not covered by the Group 2 trading 
program that happen to hold Group 2 allowances as of the conversion 
date, and (4) all general accounts (that is, accounts that are not 
facility accounts, including other accounts controlled by source owners 
as well as accounts controlled by non-source entities such as allowance 
brokers). Creating the new Group 3 allowances through conversion of 
previously banked Group 2 allowances would also help preserve the 
stringency of the Group 2 trading program for the states that remain 
covered by that trading program at levels consistent with the 
stringency found to be appropriate to address those states' good 
neighbor obligations with respect to the 2008 ozone NAAQS in the CSAPR 
Update.
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    \296\ If the proposed expansion of geographic scope for the 
Group 3 trading program is unchanged in the final rule, the states 
whose sources would continue to participate in the Group 2 trading 
program would be Iowa and Kansas.
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    With respect to setting the target amount of Group 3 allowances 
that would be created in the conversion process, the EPA proposes to 
follow the same approach that was used in the Revised CSAPR Update for 
creation of the initial Group 3 allowance bank. Specifically, the 
target amount of Group 3 allowances to be created would be computed as 
the sum of the variability limits for the 2024 control period \297\ 
established in the final rule for the states being transitioned to the 
Group 3 trading program from the Group 2 trading program, prorated to 
reflect the portion of the 2023 control period occurring on and after 
the effective date of the final rule. Based on the amounts of the 
proposed state emissions budgets and variability limits, the full-
season target amount for the conversion would be 18,517 Group 3 
allowances. The quantity of banked Group 2 allowances currently held in 
accounts other than the facility accounts of sources in Iowa and Kansas 
exceeding the quantity of allowances likely to be needed for 2021 
compliance is approximately 110,000 allowances. If the quantities of 
banked Group 2 allowances did not change between now and the conversion 
date, and if there was no prorating adjustment, the conversion ratio 
would be approximately 5.9-to-1, meaning that one Group 3 allowance 
would be created for every 5.9 Group 2 allowances deducted in the 
conversion process.\298\
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    \297\ Similar to the approach taken in the Revised CSAPR Update, 
because emissions reductions from some of the emissions controls 
that EPA has identified as appropriate to use in setting budgets are 
first reflected in the 2024 state budgets rather than the 2023 state 
budgets, the EPA is proposing to base the bank target amount on the 
sum of the states' 2024 variability limits rather than the 2023 
variability limits.
    \298\ By comparison, the analogous conversion ratio under the 
Revised CSAPR Update was 8-to-1.
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    As noted in Section VII.B.11.a of this proposed rule, it is 
possible that the effective date of this rule will occur after the 
start of the 2023 ozone season, and provisions are being proposed to 
ensure that the increased stringency of this rule's state budgets and 
state assurance levels (i.e., the sums of the budgets and variability 
limits) would take effect only after the rule's effective date. 
Consistent with these other procedures, the EPA is proposing to 
similarly prorate the bank target amount used in the conversion 
process. For example, if the effective date of the final rule is the 
eleventh day of the 153-day 2023 ozone season, the full-season initial 
bank target amount of 18,517 allowances would be prorated to an initial 
bank target amount of 17,307 allowances.\299\ The EPA notes that 
prorating the bank amount in this manner would not reduce sources' 
compliance flexibility for the 2023 ozone season, because the amounts 
of Group 3 allowances that sources would receive for the portion of the 
2023 ozone season before the rule's effective date would be based on 
the current trading program budgets for the 2023 control period before 
this rulemaking. The current trading program budgets exceed the 
sources' collective 2021 emissions by approximately 18,600 tons, 
indicating potentially surplus allowances roughly equal to the full-
season bank conversion target amount of 18,517 allowances. Thus, 
although the prorating procedure would reduce the amount of Group 3 
allowances that would be available to sources in the form of an initial 
bank, the reduction in the quantity of these allowances would be offset 
by the quantities of Group 3 allowances that would be allocated in 
excess of sources' recent historical emissions levels for the portion 
of the ozone season before the final rule's effective date.
---------------------------------------------------------------------------

    \299\ 18,517 x (153-10) / 153 = 17,307.
---------------------------------------------------------------------------

    As in the CSAPR Update and the Revised CSAPR Update, EPA's overall 
objective in establishing the target amount for the allowance 
conversion would be to achieve a total target amount for the bank at a 
level high enough to accommodate year-to-year

[[Page 20137]]

variability in operations and emissions, as reflected in states' 
variability limits, but not high enough to allow sources collectively 
to plan to emit in excess of the collective state budgets. EPA believes 
that a well-established trading program would be able to function with 
an allowance bank lower than the full amount of the covered states' 
variability limits, as discussed in section VII.B.6 with respect to the 
proposed bank recalibration process that would begin with the 2024 
control period. However, EPA also believes there are several compelling 
reasons in this instance to use a bank target higher than the minimum 
practicable level.
    First, making an allowance bank available for use in the 2023 
control period that is somewhat higher than the minimum practicable 
level would help to address concerns that might otherwise arise 
regarding the transition to a new set of compliance requirements, for 
some sources, and the transition to compliance requirements based on 
revised emissions budgets different from the emissions budgets that the 
sources had reason to anticipate under previous rulemakings, for the 
remaining sources. Although the EPA is confident that the emissions 
budgets being proposed in this rulemaking for the 2023 control period 
are readily achievable, the EPA also believes that the existence of a 
somewhat larger allowance bank at this transition point will promote 
sources' confidence in their ability to meet their 2023 compliance 
obligations in general and in a liquid allowance market in particular. 
Second, because the large majority of the remaining Group 2 allowances 
that would be converted to Group 3 allowances in this rulemaking are 
held by the sources currently in the Group 2 trading program, while the 
large majority of the initial bank of Group 3 allowances previously 
created in the conversion under the Revised CSAPR Update are held by 
the sources already in the Group 3 trading program, basing the 
conversion in this rulemaking on a target bank amount set in the same 
manner as the target bank amount used in the Revised CSAPR Update is 
expected to result in a less concentrated distribution of holdings of 
banked Group 3 allowances following the conversion than would be the 
case if a more stringent target bank amount were used under this 
rulemaking than was used in the Revised CSAPR Update. A lower 
concentration of holdings of banked Group 3 allowances would generally 
be expected to help ensure allowance market liquidity. Third, EPA 
considers it equitable to treat the sources in the states transitioning 
from the Group 2 trading program to the Group 3 trading program in this 
rulemaking roughly similarly to the sources in the states that 
transitioned between the same two trading programs in the Revised CSAPR 
Update with respect to the benefit they would receive under the Group 3 
trading program for any efforts they may have made to make emissions 
reductions under the Group 2 trading program beyond the minimum efforts 
that were required to comply with the emissions budgets under that 
program. Finally, to the extent that the proposed conversion results in 
a larger bank of allowances remaining after the 2023 control period 
than is considered necessary to sustain a well-functioning trading 
program in subsequent control periods, the excess would be removed from 
the program in the proposed bank recalibration process that would be 
implemented starting with the 2024 control period and therefore would 
not weaken sources' incentives to control emissions on a permanent 
basis.
    The EPA requests comment on the proposal to create additional 
banked Group 3 allowances through the conversion of Group 2 allowances 
banked for control periods before 2023.
c. Recall of Group 2 Allowances Allocated for Control Periods After 
2022
    To maintain the previously established levels of stringency of the 
Group 2 trading program for the states and sources that remain subject 
to that program under this proposed rule, the EPA proposes to recall 
CSAPR NOX Ozone Season Group 2 allowances equivalent in 
amount and usability to all vintage year 2023-2024 CSAPR NOX 
Ozone Season Group 2 allowances previously allocated to sources in 
Group 3 states and areas of Indian country and recorded in the sources' 
compliance accounts. The proposed recall provisions would apply to all 
sources in jurisdictions newly added to the Group 3 trading program in 
whose compliance accounts CSAPR NOX Ozone Season Group 2 
allowances for a control period in 2023 or 2024 were recorded, 
including sources where some or all units have permanently retired or 
where the previously recorded 2023-2024 allowances have been 
transferred out of the compliance account. The proposed recall 
provisions provide a flexible compliance schedule intended to 
accommodate any sources that have already transferred the previously 
recorded 2023-2024 allowances out of their compliance accounts and 
allows Group 2 allowances of earlier vintages to be surrendered to 
achieve compliance. Like the similar recall provisions finalized in the 
Revised CSAPR Update, the proposed recall provisions include 
specifications for how the recall provisions apply in instances where a 
source and its allowances have been transferred to different parties 
and for the procedures that the EPA will follow to implement the 
recall.
    Under the Group 2 trading program regulations, each Group 2 
allowance is a ``limited authorization to emit one ton of 
NOX during the control period in one year,'' where the 
relevant limitations include the EPA Administrator's authority ``to 
terminate or limit the use and duration of such authorization to the 
extent the Administrator determines is necessary or appropriate to 
implement any provision of the Clean Air Act.'' 40 CFR 
97.806(c)(6)(ii). The Administrator proposes to determine that, in 
order to effectively implement the Group 2 trading program as a 
compliance mechanism through which states not subject to the Group 3 
trading program may continue to meet their obligations under CAA 
section 110(a)(2)(D)(i)(I) with regard to the 2008 ozone NAAQS, it is 
necessary to limit the use of Group 2 allowances equivalent in quantity 
and usability to all Group 2 allowances previously allocated for the 
2023-2024 control periods and recorded in the compliance accounts of 
sources in the newly added Group 3 jurisdictions. The Group 2 
allowances that have already been allocated to sources in the newly 
added Group 3 states for the 2023-2024 control periods and recorded in 
the sources' compliance accounts represent the substantial majority of 
the total remaining quantity of Group 2 allowances that have been 
allocated and recorded for the 2023-2024 control periods and that were 
not already made subject to recall when other jurisdictions were 
transferred from the Group 2 trading program to the Group 3 trading 
program in the Revised CSAPR Update. Because allowances can be freely 
traded, if the use of the 2023-2024 Group 2 allowances previously 
recorded in newly added Group 3 sources' compliance accounts (or 
equivalent Group 2 allowances) were not limited, the effect would be 
the same as if the EPA had issued to sources in the states that will 
remain covered by the Group 2 trading program a quantity of allowances 
available for compliance under the 2023-2024 control periods many times 
the levels that the EPA determined to be appropriate emissions budgets 
for these states in the CSAPR Update. Through the use of banked 
allowances, the excess Group 2

[[Page 20138]]

allowances would affect compliance under the Group 2 trading program in 
control periods after 2024 as well. Continued implementation of the 
Group 2 trading program at levels of stringency consistent with the 
levels contemplated under the CSAPR Update therefore requires that the 
EPA limit the use of the excess allowances, as the EPA is proposing 
here.
    In this rulemaking, the EPA proposes to implement limitations on 
the use of the excess 2023-2024 Group 2 allowances through requirements 
to surrender, for each 2023-2024 Group 2 allowance recorded in a newly 
added Group 3 source's compliance account, one Group 2 allowance of 
equivalent usability under the Group 2 trading program. The surrender 
requirements would apply to the owners and operators of the Group 3 
sources in whose compliance account the excess 2023-2024 Group 2 
allowances were initially recorded. In general, each source's current 
owners and operators would be required to comply with the surrender 
requirements for the source by ensuring that sufficient allowances to 
complete the deductions are available in the source's compliance 
account by one of two possible deadlines discussed below. However, an 
exception would be provided if a source's current owners and operators 
obtained ownership and operational control of the source in a 
transaction that did not include rights to direct the use and transfer 
of some or all of the 2023-2024 Group 2 allowances allocated and 
recorded (either before or after that transaction) in the source's 
compliance account. The proposed rule provides that in such a 
circumstance, with respect to the 2023-2024 Group 2 allowances for 
which rights were not included in the transaction, the surrender 
requirements would apply to the most recent former owners and operators 
of the source before any such transactions occurred. Because in this 
situation a source's former owners and operators might lack the ability 
to access the source's compliance account for purposes of complying 
with the surrender requirements, the former owners and operators would 
instead be allowed to meet the surrender requirements with Group 2 
allowances held in a general account.\300\
---------------------------------------------------------------------------

    \300\ The EPA is currently unaware of any source that would need 
to use this flexibility but has included the option in the proposal 
to address the theoretical possibility of such a situation.
---------------------------------------------------------------------------

    To provide as much flexibility as possible consistent with the need 
to limit the use of the excess Group 2 allowances, for each 2023-2024 
Group 2 allowance recorded in a Group 3 source's compliance account, 
the EPA proposes to accept the surrender of either the same specific 
2023-2024 Group 2 allowance or any other Group 2 allowance with 
equivalent (or greater) usability under the Group 2 trading program. 
Thus, a surrender requirement with regard to a Group 2 allowance 
allocated for the 2023 control period could be met through the 
surrender of any Group 2 allowance allocated for the 2023 control 
period or the control period in any earlier year--in other words, any 
2017-2023 Group 2 allowance.\301\ Similarly, the surrender requirement 
with regard to a 2024 Group 2 allowance could be met through the 
surrender of any 2017-2024 Group 2 allowance.
---------------------------------------------------------------------------

    \301\ The first control period for the Group 2 trading program 
was in 2017.
---------------------------------------------------------------------------

    Owners and operators subject to the surrender requirements could 
choose from two possible deadlines for meeting the requirements. The 
first deadline would be 15 days after the effective date of a final 
rule in this rulemaking.\302\ As soon as practicable or after this 
date, the EPA would make a first attempt to complete the deductions of 
Group 2 allowances required for each Group 3 source from the source's 
compliance account. The EPA would deduct Group 2 allowances first to 
address any surrender requirements for the 2023 control period and then 
to address any surrender requirements for the 2024 control period. When 
deducting Group 2 allowances to address the surrender requirements for 
each control period, EPA would first deduct allowances allocated for 
that control period and then would deduct allowances allocated for each 
successively earlier control period. This order of deductions is 
intended to ensure that whatever Group 2 allowances are available in 
the account are applied to the surrender requirements in a manner that 
both maximizes the extent to which all of the source's surrender 
requirements would be met and also ensures that any Group 2 allowances 
left in the source's compliance account after completion of all 
required deductions would be the earliest allocated, and therefore most 
useful, Group 2 allowances possible. Among the Group 2 allowances 
allocated for a given control period, The EPA would first deduct 
allowances that were initially recorded in that account, in the order 
of recordation, and would then deduct allowances that were transferred 
into that account after having been initially recorded in some other 
account, in the order of recordation.
---------------------------------------------------------------------------

    \302\ As discussed later in this section and in Section 
VII.B.9.b, the EPA is proposing to condition recordation of any 
allocations of Group 3 allowances in a source's compliance account 
on the source's prior compliance with the proposed recall 
requirements for Group 2 allowances. The purpose of providing a 
first deadline for the recall provisions 15 days after a final 
rule's effective would be to ensure that sources have an early 
opportunity to comply with the recall provisions in order to be 
eligible to have allocations of Group 3 allowances recorded in their 
accounts as proposed 30 days after the final rule's effective date. 
Because the vast majority of sources subject to the proposed recall 
provisions already hold sufficient Group 2 allowances to comply with 
the recall provisions, the EPA anticipates that the sources would 
easily be able to comply with the proposed first recall deadline.
---------------------------------------------------------------------------

    Following the first attempt to deduct Group 2 allowances to address 
Group 3 sources' surrender requirements, the EPA would send a 
notification to the designated representative for each such source (as 
well as any alternate designated representative) indicating whether all 
required deductions were completed and, if not, the additional amounts 
of Group 2 allowances usable in the 2023 or 2024 control periods that 
must be held in the appropriate account by the second surrender 
deadline of September 15, 2023. Each notification would be sent to the 
email addresses most recently provided to the EPA for the recipients 
and would include information on how to contact the EPA with any 
questions. The EPA proposes that no allocations of Group 3 allowances 
would be recorded in a source's compliance account until all the 
source's surrender requirements with regard to 2023-2024 Group 2 
allowances have been met. For this reason, the principal consequence to 
a source of failure to fully comply with the surrender requirements by 
15 days after the effective date of a final rule would be that any 
Group 3 allowances allocated to the units at the source for the 2023 
and 2024 control periods that would otherwise have been recorded in the 
source's compliance account by 30 days after the effective date of a 
final rule would not be recorded as of that recordation date.
    If all surrender requirements of 2023-2024 Group 2 allowances for a 
source have not been met in EPA's first attempt, the EPA would make a 
second attempt to complete the required deductions from the source's 
compliance account (or from a specified general account, in the limited 
circumstance noted above) as soon as practicable on or after September 
15, 2023. The order in which Group 2 allowances are deducted would be 
the same as described above for the first attempt.
    If the second attempt to deduct Group 2 allowances to meet the 
surrender requirements through deductions from the source's compliance 
account (or

[[Page 20139]]

from a specified general account) is unsuccessful for a given source, 
the EPA proposes that as soon as practicable on or after November 15, 
2023, to the extent necessary to address the unsatisfied surrender 
requirements for the source, the EPA would deduct the 2023-2024 Group 2 
allowances that were initially recorded in the source's compliance 
account from whatever accounts the allowances are held in as of the 
date of the deduction, except for any allowances where, as of April 1, 
2022, no person with an ownership interest in the allowances was an 
owner or operator of the source, was a direct or indirect parent or 
subsidiary of an owner or operator of the source, or was directly or 
indirectly under common ownership with an owner or operator of the 
source.\303\ Before making any deduction under this provision, the EPA 
would send a notification to the authorized account representative for 
the account in which the allowance is held and would provide an 
opportunity for submission of objections concerning the data upon which 
the EPA is relying. In EPA's view, this provision would not unduly 
interfere with the legitimate expectations of participants in the 
allowance markets because the provision would not be invoked in the 
case of any allowance that was transferred to an independent party in 
an arms-length transaction before EPA's intent to recall 2023-2024 
Group 2 allowances became widely known. The provision would apply only 
to a Group 2 allowance that, as of April 1, 2022, was still controlled 
either by the owners and operators of the source in whose compliance 
account it was initially recorded or by an entity affiliated with such 
an owner or operator. The EPA believes that by April 1, 2022, all 
market participants will have had ample opportunity to become informed 
of the proposed rule provisions to recall 2023-2024 Group 2 allowances 
recorded in Group 3 sources' compliance accounts, particularly since 
the EPA implemented a closely analogous recall of Group 2 allowances in 
the Revised CSAPR Update.\304\
---------------------------------------------------------------------------

    \303\ The proposed provision under which the EPA would not 
deduct Group 2 allowances transferred to unrelated parties before 
April 1, 2022 from the transferees' accounts would not relieve the 
source to which the Group 2 allowances were originally allocated 
from the obligation to comply with the recall requirements. 
Specifically, the source would be required to comply with the recall 
requirements by obtaining and surrendering other Group 2 allowances.
    \304\ Even before publication of the proposed rule, the EPA 
posted information on its websites to notify market participants 
that a pending rulemaking could have consequences for the value and 
usability of Group 2 allowances. The posted locations included the 
electronic portal that authorized account representatives use to 
enter allowance transfers for recordation by the EPA in the 
Allowance Management System. Additionally, the EPA emailed a notice 
identifying the possibility of such consequences to the 
representatives for all Allowance Management System accounts.
---------------------------------------------------------------------------

    The EPA proposes that failure of a source's owners and operators to 
comply with the surrender requirements would be subject to possible 
enforcement as a violation of the CAA, with each allowance and each day 
of the control period constituting a separate violation.
    To eliminate any possible uncertainty regarding the amounts of 
Group 2 allowances allocated for the 2023-2024 control periods (or 
earlier control periods) that the owners and operators of each Group 3 
source would be required to surrender under the recall provisions, the 
EPA has prepared a list of the sources in the proposed additional Group 
3 states and areas of Indian country in whose compliance accounts 
allocations of 2023-2024 Group 2 allowances were recorded, with the 
amounts of the allocations recorded in each such compliance account for 
the 2023 and 2024 control periods. An additional list shows, for each 
newly added Group 3 source, the specific Group 2 allowances (batched by 
serial number) allocated for each control period and recorded in the 
source's compliance account and indicates whether, as of December 31, 
2021, that batch of allowances was held in the source's compliance 
account, in an account believed to be partially or fully controlled by 
a related party (i.e., an owner or operator of the source or an 
affiliate of an owner or operator of the source), or in an account 
believed to be fully controlled by independent parties. The lists are 
in a spreadsheet titled, ``Recall of Additional CSAPR NOX 
Ozone Season Group 2 Allowances'', available in the docket for this 
proposed rule. After the first and second surrender deadlines, the EPA 
intends to update the lists to indicate for each Group 3 source whether 
the surrender requirements for the source under the recall provisions 
have been fully satisfied. The EPA would post the updated lists on a 
publicly accessible website to ensure that all market participants have 
the ability to determine which specific 2023-2024 Group 2 allowances 
initially recorded in any given Group 3 source's compliance account do 
or do not remain subject to potential deduction to address the source's 
surrender requirements under the recall provisions.
    The EPA requests comment on the proposal to recall Group 2 
allowances equivalent in quantity and usability to the Group 2 
allowances previously issued for the 2023 and 2024 control periods and 
recorded in the compliance accounts of sources in jurisdictions being 
newly added to the Group 3 trading program in this proposed rule.
12. Conforming Revisions to Other Regulations
    As noted in Section VII.B.1.a of this proposed rule, in addition to 
the Group 3 trading program, EPA currently administers five other CSAPR 
trading programs, all of which have provisions that in most respects 
parallel the provisions of the Group 3 trading program.\305\ The EPA 
also administers the Texas SO2 Trading Program, whose 
provisions parallel the provisions of the CSAPR trading programs to a 
somewhat lesser extent.\306\ In this rulemaking, in addition to the 
proposed revisions to the Group 3 trading program, the EPA is proposing 
a small number of conforming revisions to the other CSAPR trading 
programs and/or the Texas SO2 Trading Program to maintain 
consistency across the regulations for the various trading programs to 
the extent possible.
---------------------------------------------------------------------------

    \305\ The regulations for the Group 3 Trading Program are at 40 
CFR 97, subpart GGGGG. The regulations for the other five CSAPR 
trading programs are at 40 CFR part 97, subparts AAAAA, BBBBB, 
CCCCC, DDDDD, and EEEEE.
    \306\ The regulations for the Texas SO2 Trading 
Program are at 40 CFR part 97, subpart FFFFF.
---------------------------------------------------------------------------

    The first set of proposed conforming revisions concerns the use of 
the term ``Indian country'' in the allowance allocation provisions of 
the regulations for all the CSAPR trading programs. As discussed in 
Section VII.B.9.a of this proposed rule, to reflect the D.C. Circuit's 
holding in ODEQ v. EPA that states have initial CAA implementation 
planning authority in non-reservation areas of Indian country until 
displaced by a demonstration of tribal jurisdiction over such an area, 
the EPA is proposing to revise the allowance allocation provisions in 
the Group 3 trading program regulations so that, instead of 
distinguishing between the sets of units within a given state's borders 
that either are not or are in Indian country, the revised regulations 
would distinguish between (1) the set of units within the state's 
borders that are not in Indian country or are in areas of Indian 
country covered by the state's CAA implementation planning authority 
and (2) the set of units within the state's borders that are in areas 
of Indian country not covered by the state's CAA implementation 
planning authority. For the same reasons stated in Section VII.B.9.a of 
this proposed rule for the

[[Page 20140]]

Group 3 trading program, the EPA proposes to make revisions to the 
allowance allocation provisions in the regulations for all the other 
CSAPR trading programs establishing the same substantive distinction 
among the sets of units within each state's borders. The specific 
regulatory provisions that would be affected are identified in Section 
X of this proposed rule. The EPA is unaware of any currently operating 
units that would be affected by this proposed revision to the 
regulations for the other CSAPR trading programs.
    The second set of proposed conforming revisions concerns the 
schedule for recording allocations of allowances to existing units. To 
maintain consistency with the provisions of the revised Group 3 Trading 
Program to the extent possible, the EPA proposes to revise the 
regulations for each of the other five CSAPR trading programs and the 
Texas SO2 Trading Program to reflect whatever revised 
schedule for recording most allowance allocations the EPA may adopt for 
the revised Group 3 trading program in a final rule in this rulemaking. 
The proposed revisions to the recordation deadlines would affect only 
the timing of recordation, not the amounts of allowances allocated to 
and recorded for any source for any control period.
    The effect of the proposed revisions would be to establish a new 
common recordation schedule for all the CSAPR trading programs and the 
Texas SO2 Trading Program. Assuming the common schedule 
adopted is the specific schedule proposed for the Group 3 trading 
program in Section VII.B.9 of this proposed rule, allocations from the 
portion of each state emissions budget under each program not reserved 
in a set-aside would be recorded by July 1 of the year immediately 
preceding the year of the relevant control period. Under the current 
regulations before the proposed revisions, the equivalent recordation 
deadline is July 1 of the year three years before the year of the 
relevant control period. Relatedly, the EPA also proposes to revise the 
deadline for states to submit any state-determined allocations to the 
EPA under each trading program to June 1 of the year immediately 
preceding the year of the relevant control period, instead of June 1 of 
the year three years before the year of the relevant control 
period.\307\
---------------------------------------------------------------------------

    \307\ The regulations for the various programs already establish 
a common recordation schedule for the portion of each state 
emissions budget set aside for possible allocation to new units--
namely, by May 1 of the year after the year of the relevant control 
period. The related deadline for states to submit any state-
determined allocations of these allowances to the EPA under each 
program is April 1 of the year after the year of the relevant 
control period.
---------------------------------------------------------------------------

    This EPA believes that revising the recordation schedules as 
proposed to establish a new common recordation schedule for the 
affected trading programs would make the programs procedurally more 
consistent, generally reducing the time and cost expended by sources to 
understand and comply with multiple trading programs. Greater 
consistency across the various programs would also support greater 
administrative efficiency by the EPA and by states that elect to 
determine allowances allocations under the various programs. In 
addition, by reducing the number of future control periods for which 
allowances are recorded, the proposed revisions would reduce the 
likelihood that the EPA might need to recall already-recorded 
allowances as part of a transition for some sources to new regulatory 
requirements in a future rulemaking. The EPA has implemented such a 
recall in the Revised CSAPR Update and has proposed to implement a 
similar recall in this rulemaking.
    Finally, the EPA believes that revising the recordation schedules 
for the other CSAPR trading programs and the Texas SO2 
Trading Program as proposed would not adversely impact allowance market 
liquidity. Allowances issued for control periods through 2024 under 
each of these programs were recorded by July 1, 2020. As of December 
2021, although recorded private transfers of earlier vintage allowances 
usable for 2021 compliance have been increasing in advance of the 
upcoming June 1, 2022, compliance deadline for the 2021 control 
periods, few allowances recorded for the 2023 or 2024 control periods 
(or even the 2022 control period) under any of the programs have been 
transferred out of the accounts in which they were initially recorded, 
except as needed to comply with the recall of certain allowances under 
the Revised CSAPR Update. Moreover, most of the recorded transfers of 
allowances issued for 2022, 2023, and 2024 have been between accounts 
controlled by the same entity, corporate affiliates, or other related 
entities (such as unit co-owners) rather than between accounts 
controlled by unrelated parties. The EPA therefore believes there would 
have been little effect on arms-length allowance market activity in 
these programs if the proposed revised recordation schedule had already 
been in effect and the allowances for 2023 and 2024 consequently had 
not yet been recorded.
    Further details on the specific regulatory provisions that would be 
affected by the proposed revisions to allowance allocation recordation 
schedules are provided in Section X of the proposed rule.
    The EPA requests comment on the proposed revision to the definition 
of ``Indian country'' under the CSAPR NOX Annual, 
NOX Ozone Season Group 1, SO2 Group 1, 
SO2 Group 2, and NOX Ozone Season Group 2 Trading 
Programs and the proposed revisions to the allowance allocation 
recordation deadlines under the CSAPR NOX Annual, 
NOX Ozone Season Group 1, SO2 Group 1, 
SO2 Group 2, and NOX Ozone Season Group 2 Trading 
Programs and the Texas SO2 Trading Program.

C. Regulatory Requirements for Non-EGUs

    The EPA is proposing that the FIPs for 23 of the states covered in 
this proposed rule will include new emissions limitations on emissions 
units in seven non-EGU industries that EPA finds (as discussed in 
Section VI of this proposed rule) to be significantly contributing to 
nonattainment or interfering with maintenance in other states.
    In order to achieve the necessary non-EGU emissions reductions for 
the 23 states, the EPA proposes emissions limitations for the most 
impactful units in the relevant industries that are achievable with the 
control technologies identified in the Step 3 analysis. The EPA is 
proposing a direct control approach with rate-based limits, production-
based limits, and work practice standards set on a uniform basis for 
the different segments of non-EGU emissions units using applicability 
criteria based on size and type of unit and, in some cases, emissions 
thresholds. The EPA believes this approach can achieve the requisite 
level of emissions reductions from the covered units through the 
assignment of emissions limits that are achievable across the entire 
segment. The EPA believes that establishing emissions limits for 
emissions units based on size and type of unit and, in some cases, 
emissions thresholds, will achieve the necessary reductions without 
requiring a unit-by-unit assessment.\308\ By

[[Page 20141]]

establishing uniform emissions limits for categories of units rather 
than on a unit-by-unit basis, the EPA can also ensure that any new 
source of emissions constructed after this proposed rulemaking are also 
subject to the emissions limits identified later (see Section IV.B.1.d 
of this proposed rule).
---------------------------------------------------------------------------

    \308\ If an emissions unit installs SCR or SNCR to meet an 
emissions limit in response to the proposed FIP that would be a 
physical change under new source review (NSR) and lead to an 
assessment of potential emissions changes. If the installation of 
SCR results in an emissions increase that exceeds the thresholds in 
the NSR regulations for one or more regulated NSR pollutants, 
including the netting analysis, the changes would trigger the 
applicability of NSR.
---------------------------------------------------------------------------

    The EPA recognizes that the numerous variables that contribute to 
differences in units' emissions rates may complicate development of 
limits for groups of units as large as those addressed in this proposed 
rule. For each emissions source category, the EPA considered the range 
of emissions limits that currently apply to these sources under other 
CAA programs, such as RACT, NSPS, NESHAP, and OTC model rules, to 
develop an emissions limit that should be achievable by all sources 
after installing the controls identified in the Step 3 analysis. For a 
detailed discussion of the technical bases for EPA's proposed 
requirements for non-EGU emissions units, see the Non-EGU Sectors TSD.
    The EPA is proposing that the emissions limits and compliance 
requirements for non-EGUs will apply only during the ozone season 
(which runs annually from May-September). This is consistent with EPA's 
prior practice in federal actions to eliminate significant contribution 
of ozone in the 1998 NOX SIP Call, CAIR, CSAPR, CSAPR 
Update, and the Revised CSAPR Update. EPA is seeking comment on whether 
non-EGU sources would run controls that would be installed as a result 
of this proposed FIP year-round (i.e., will some source categories run 
their controls year-round due to the nature of those controls?).
    In addition, the EPA proposes to apply the FIP requirements to all 
existing emissions units and any future emissions units constructed 
after the promulgation of a final rule. Further, the non-EGU emissions 
limits and compliance requirements will apply in all 23 states (and, as 
discussed in Section IV.C.2 of this proposed rule, in areas of Indian 
country within the borders of those states), even if some of those 
states do not currently have emissions units in a particular source 
category. This approach will ensure that all new sources constructed in 
any of the 23 states will be subject to the same regulatory 
requirements as applied for the existing units under this proposed 
rule. This will also mitigate any potential incentive to move 
production from an existing non-EGU source in one linked state to a new 
non-EGU source of the same type but lacking the relevant emissions 
control requirements in another linked state.
    At this time, this EPA is not proposing to include non-EGUs in the 
trading program described in this proposed rule. If EPA were to include 
non-EGUs in the trading program, we would require monitoring and 
reporting of hourly mass emissions in accordance with 40 CFR part 75 as 
we have required for all trading programs. Monitoring and reporting 
under part 75 include CEMS (or an approved alternative method), 
rigorous initial certification testing, and periodic quality assurance 
testing thereafter, such as relative accuracy test audits and daily 
calibrations. This type of consistent and accurate measurement of 
emissions is necessary to ensure each allowance actually represents one 
ton of emissions and that one ton of reported emissions from one source 
would be equivalent to one ton of reported emissions from another 
source. See 75 FR 45325 (August 2, 2010). Moreover, these monitoring 
requirements generally would need to be in place for at least one full 
ozone season to establish baseline data before it would be appropriate 
to rely on a trading program as the mechanism to achieve the required 
emissions reductions. Therefore, at this time, the EPA believes that 
applying unit-level emissions limitations on non-EGU emissions units 
rather than constructing an emissions trading regime is more 
administratively feasible and more easily implementable at the source 
level, and it will effectively eliminate each state's significant 
contribution without the need for establishing a new emissions trading 
program.
    The EPA is proposing to require electronic reporting for all seven 
non-EGU industries. Specifically, owners and operators of affected 
units must submit electronic copies of required performance test 
reports, performance evaluation reports, quarterly and semi-annual 
reports, and excess emissions reports through EPA's Central Data 
Exchange (CDX) using the Compliance and Emissions Data Reporting 
Interface (CEDRI). The EPA is proposing to require that performance 
test results collected using test methods that are supported by EPA's 
Electronic Reporting Tool (ERT) as listed on the ERT website \309\ at 
the time of the test be submitted in the format generated through the 
use of the ERT or an electronic file consistent with the xml schema on 
the ERT website, and that other performance test results be submitted 
in portable document format (PDF) using the attachment module of the 
ERT. Similarly, the EPA is proposing to require that performance 
evaluation results of CEMS measuring relative accuracy test audit 
(RATA) pollutants that are supported by the ERT at the time of the test 
be submitted in the format generated through the use of the ERT or an 
electronic file consistent with the xml schema on the ERT website, and 
that other performance evaluation results be submitted in PDF using the 
attachment module of the ERT. In addition, the EPA is proposing to 
require that quarterly and semi-annual reports and excess emissions 
reports be submitted in PDF uploaded in CEDRI.
---------------------------------------------------------------------------

    \309\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    The EPA is proposing to allow for an extension of time to file a 
report where an owner or operator demonstrates that it cannot meet the 
reporting deadline for reasons outside of its control. Specifically, 
the EPA has identified two broad circumstances under which the EPA may 
grant a request for an extension of time to file an electronic report. 
These circumstances are (1) outages of EPA's CDX or CEDRI which 
preclude an owner or operator from accessing the system and submitting 
required reports and (2) force majeure events, which are defined as 
events that will be or have been caused by circumstances beyond the 
control of the affected facility, its contractors, or any entity 
controlled by the affected facility that prevent an owner or operator 
from complying with the requirement to submit a report electronically. 
Examples of force majeure events are acts of nature, acts of war or 
terrorism, or equipment failure or safety hazards beyond the control of 
the facility. In both circumstances, the decision to grant an extension 
of time to report is within the discretion of the Administrator, and 
reporting should occur as soon as possible.
    Electronic submittal of required reports will increase the 
usefulness of the data contained in those reports, is in keeping with 
current trends in data availability and transparency, will further 
assist in the protection of public health and the environment, will 
improve compliance by facilitating the ability of regulated facilities 
to demonstrate compliance with requirements and by facilitating the 
ability of the EPA to assess and determine compliance, and will 
ultimately reduce burden on regulated facilities and the EPA. 
Electronic reporting also eliminates paper-based, manual processes, 
thereby saving time and resources, simplifying data entry, eliminating 
redundancies, minimizing

[[Page 20142]]

data reporting errors, and providing data quickly and accurately to the 
affected facilities, air agencies, EPA, and the public. Moreover, 
electronic reporting is consistent with EPA's plan \310\ to implement 
Executive Order 13563 and is in keeping with EPA's agency-wide policy 
\311\ developed in response to the White House's Digital Government 
Strategy.\312\
---------------------------------------------------------------------------

    \310\ EPA's Final Plan for Periodic Retrospective Reviews, 
August 2011. Available at: https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154.
    \311\ E-Reporting Policy Statement for EPA Regulations, 
September 2013. Available at: https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf.
    \312\ Digital Government: Building a 21st Century Platform to 
Better Serve the American People, May 2012. Available at: https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html. For more information on the 
benefits of electronic reporting, see the memorandum Electronic 
Reporting Requirements for New Source Performance Standards (NSPS) 
and National Emission Standards for Hazardous Air Pollutants 
(NESHAP) Rules, referenced earlier in this section.
---------------------------------------------------------------------------

    The EPA notes that no emissions standard or other requirement 
established for non-EGUs in these FIPs may be interpreted, construed, 
or applied to diminish or replace the requirements of any emissions 
limitation or other applicable requirement established by the 
Administrator pursuant to other CAA authority or a standard issued 
under State authority.
1. Pipeline Transportation of Natural Gas
Applicability
    The EPA is proposing to establish regulatory requirements for the 
Pipeline Transportation of Natural Gas industry that apply to 
stationary, natural gas-fired, spark ignited reciprocating internal 
combustion engines (``stationary SI engines'') within these facilities 
that have a maximum rated capacity of 1,000 horsepower (hp) or greater. 
Based on our review of the potential emissions from stationary SI 
engines, we find that use of a maximum rated capacity of 1,000 hp 
reasonably approximates the selection of 100 tpy used within the non-
EGU screening assessment. Therefore, stationary SI engines subject to 
the proposed rule requirements of this section are those found within 
any of the 23 covered states with non-EGU emissions reduction 
obligations that are within the Pipeline Transportation of Natural Gas 
industry and have a maximum rated capacity of 1,000 hp or greater.
Emissions Limitations and Rationale
    In developing the emissions limits for the Pipeline Transportation 
of Natural Gas industry, EPA reviewed RACT NOX rules, air 
permits, and OTC model rules. While some permits and rules express 
engine emissions limits in parts per million by volume (pmmv), the 
majority of rules and source-specific requirements express the 
emissions limits in grams per horsepower per hour (g/hp-hr). The EPA 
has historically set emissions limits for these types of engines using 
g/hp-hr and finds that method appropriate for this proposed FIP as 
well.
    Based on the available information for this industry, applicable 
State and local air agency rules, and active air permits issued to 
sources with similar engines, the EPA is proposing the following 
emissions limits for stationary SI engines in the covered states:

  Table VII.C-1--Summary of Proposed NOX Emissions Limits for Pipeline
                      Transportation of Natural Gas
------------------------------------------------------------------------
                                   Proposed NOX          Additional
     Engine type and fuel        emissions limit        information
------------------------------------------------------------------------
Natural Gas Fired Four Stroke   1.0 g/hp-hr......  Limits reviewed
 Rich Burn.                                         ranged between 0.2
                                                    and 3.0 g/hp-hr.
Natural Gas Fired Four Stroke   1.5 g/hp-hr......  Limits reviewed
 Lean Burn.                                         ranged between 0.5
                                                    and 3.0 g/hp-hr.
Natural Gas Fired Two Stroke    3.0 g/hp-hr......  Limits reviewed
 Lean Burn.                                         ranged between 0.5
                                                    and 3.0 g/hp-hr.
------------------------------------------------------------------------

    With regard to four stroke rich burn engines, the EPA is proposing 
an emissions limit of 1.0 g/hp-hr. This limit is designed to be 
achievable by installing Non-Selective Catalytic Reduction (NSCR) on 
existing four stroke rich burn engines, as identified in the non-EGU 
screening assessment. Sources are free to install another control 
technology besides NSCR as long as the unit is still able to meet the 
emissions limit. In particular for four stroke rich burn engines, NSCR 
can be an effective control technology due to the low oxygen percentage 
in the exhaust. Efficient operation of the catalyst in NSCR requires 
the engine exhaust gases contain no more than 0.5 percent oxygen, which 
makes rich burn engines uniquely suitable to NCSR. Given that NSCR can 
achieve NOX reductions of 90 to 99 percent, the EPA believes 
an emissions limit of 1.0 g/hp-hr should be readily achievable by all 
four stroke rich burn engines subject to this proposed rulemaking. The 
EPA is taking comment on whether a lower emissions limit is more 
appropriate since even an assumed reduction of 95 percent would result 
in most engines being able to achieve an emissions rate of 0.5 g/hp-hr. 
However, at this time, the EPA does not have the information necessary 
to determine if a lower emissions limit is achievable for the four 
stroke rich burn engines subject to the proposed rulemaking, and 
therefore, the EPA is proposing an emissions limit of 1.0 g/hp-hr.
    With regard to four stroke lean burn engines, the EPA is proposing 
an emissions limit of 1.5 g/hp-hr. This limit is designed to be 
achievable by installing SCR on existing four stroke lean burn engines. 
Sources are free to install another control technology with or without 
SCR as long as the unit is still able to meet the emissions limit. For 
example, it might be more cost effective on an ongoing basis for some 
four stroke lean burn engines to install layered combustion controls 
alone or along with SCR to achieve the necessary emissions reductions. 
Information available to the EPA suggests that some four stroke lean 
burn engines can achieve 90% reductions from layered combustion 
controls alone, such as turbochargers and inter-cooling, pre-chamber 
ignition or high energy ignition, improved fuel injection control, air/
fuel ratio control.\313\ Independent of unit specific considerations, 
the EPA believes that four stroke lean burn engines subject to this 
proposed FIP can achieve an emissions limit of 1.5 g/hp-hr with the 
installation and operation of SCR or other control technologies at the 
marginal cost threshold of $7,500 per

[[Page 20143]]

ton identified in the non-EGU screening assessment. While a lower 
emissions limit may be achievable with SCR for some four stroke lean 
burn engines, the achievability of those lower limits may depend on 
engine age and come with increased costs not accounted for in this 
proposed rule. The EPA is seeking comment on whether a lower and higher 
emissions limit is appropriate for these units.
---------------------------------------------------------------------------

    \313\ Ozone Transport Commission, Technical Information Oil and 
Gas Sector Significant Stationary Sources of NOX Emissions, 35-39, 
October 17, 2012.
---------------------------------------------------------------------------

    For two stroke lean burn engines, the EPA is currently proposing an 
emissions limit of 3.0 g/hp-hr. This limit is designed to be achievable 
by retrofitting existing two stroke lean burn engines with layered 
combustion to achieve this emissions limit. Sources are free to install 
another control technology besides layered combustion as long as the 
unit is still able to meet the emissions limit. As identified in the 
non-EGU screening assessment, the EPA believes that layered combustion 
controls, such as improved airflow, improved fuel to air mixing, 
improved ignition, and modern engine electronic controls can be 
achieved on two stroke engines at the marginal cost threshold of $7,500 
per ton. With these types of controls, the information currently 
available to the EPA indicates that the amount of achievable emissions 
reductions is unit specific and can range from a 60 to 90 percent 
reduction in NOX emissions. The EPA estimates that existing 
uncontrolled two stroke lean burn engines would need to reduce 
emissions by about 80 percent to comply with a 3.0 g/hp-hr emissions 
limit. While some RACT and model rules reviewed contained more 
stringent emissions limits for two stroke lean burn engines, the EPA 
does not have information adequate to conclude that the two stroke lean 
burn engines across all 23 states can meet a lower limit. Further, some 
information available supports a finding that an emissions limit below 
3.0 g/hp-hr might not be achievable with layered combustion controls 
alone for some units, and those units would require additional controls 
beyond our cost threshold.\314\ Therefore, the EPA is proposing an 
emissions limit of 3.0 g/bhp-hr for two stroke engines. The EPA is 
seeking comment on whether a lower emissions limit would be achievable 
with layered combustion alone for the sources covered by this FIP. 
Further, the EPA is seeking comment on whether additional control 
technology could be installed on these sources at or below the marginal 
cost threshold to achieve a lower emissions rate.
---------------------------------------------------------------------------

    \314\ Ozone Transport Commission, Technical Information Oil and 
Gas Sector Significant Stationary Sources of NOX Emissions at 24-25.
---------------------------------------------------------------------------

Compliance Assurance Requirement
    The EPA is proposing to require stationary SI engines subject to 
this proposed FIP to conduct semi-annual performance testing in 
accordance with 40 CFR 60.8 to ensure that the engine is meeting the 
NOX emissions limit. The EPA is proposing that affected 
engines then monitor and record hours of operation and fuel consumption 
to calculate ongoing compliance with the applicable emissions limit. In 
addition, the EPA is proposing that affected engines would use 
continuous parametric monitoring systems (CPMS) to ensure that the 
NOX emissions limit is being met at all times. For example, 
engines utilizing layered combustion controls would need to monitor and 
record temperature, air to fuel ratio, and other parameters as 
appropriate to ensure that combustion conditions are optimized to 
reduce NOX emissions and assure compliance with the 
emissions limit. For engines using SCR or NSCR, the EPA is proposing 
that source monitor and record parameters such as inlet temperature to 
the catalyst and pressure drop across the catalyst.
    The EPA is seeking comment on whether it is feasible or appropriate 
to require affected engines to be equipped with continuous emissions 
monitoring systems (CEMS) to measure and monitor the NOx 
emissions instead of conducting performance tests on a semiannual 
basis.
2. Cement and Concrete Product Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the 
Cement and Concrete Product Manufacturing source category that apply to 
emissions units (kilns) that directly emit or have the potential to 
emit 100 tpy or more of NOX. Further, the EPA is proposing 
emissions limits based on type of unit to ensure that the necessary 
NOX emissions reductions occur. The EPA is seeking comment 
on whether it should set an applicability threshold based on a unit's 
design production capacity rather than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Cement and Concrete 
Manufacturing industry, the EPA reviewed RACT NOX rules, air 
permits, and consent decrees. These rules and source-specific 
requirements most commonly express the emissions limits for this 
industry in terms of mass of pollutant emitted (pounds) per kiln's 
clinker output (tons), i.e., pounds of NOX emitted per ton 
of clinker produced. A regulated entity routinely monitors and keeps 
track of its clinker output as it pertains to a kiln design capacity 
and the plant's production. Therefore, the EPA believes that this form 
of NOX emissions limit is effective, practicable and 
convenient to record and report to an air agency.
    In determining the averaging time for the limit, the EPA considered 
the NSPS for Portland Cement Plants at 40 CFR part 60, subpart F. 
Section 60.62(a)(3) of this subpart establishes a 30-operating day 
rolling average period for the NOX emitted per ton of 
clinker produced and further states that an operating day includes all 
valid data obtained in any daily 24-hour period during which the kiln 
operates and excludes any measurements made during the daily 24-hour 
period when the kiln was not operating. In addition, 40 CFR 60.44b(i) 
requires that compliance with the applicable NOX emissions 
limit be determined on a 30-day rolling average basis. The EPA is 
proposing to require a 30-operating day rolling average period as the 
averaging time frame for this particular industry. The proposed 
averaging timeframe is consistent with the longstanding national 
technology-based NSPS for this industry at 40 CFR part 60, subpart F. 
Furthermore, an air agency may choose to require an averaging period 
shorter than a 30-operating day rolling average in air permit(s) issued 
to these plants. The EPA finds that a 30-operating day rolling average 
period provides a reasonable balance between short term (hourly or 
daily) and long term (annual) averaging periods, while being flexible 
and responsive to fluctuations in operations and production.
    Based on the available information for this industry, applicable 
State and local air agency rules, and active air permits or enforceable 
orders issued to affected cement plants, the EPA is proposing the 
following emissions limits for cement kilns:

[[Page 20144]]



      Table VII.C-2--Summary of Proposed NOX Emissions Limits for Kiln Types in Cement and Concrete Product
                                                  Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                        Proposed NOX
                    Kiln type                       emissions limit (lb/          Additional information
                                                      ton of clinker)
----------------------------------------------------------------------------------------------------------------
Long Wet.........................................                    4.0  Limits reviewed ranged between 3.88-
                                                                           5.2; one State rule allows as high as
                                                                           6.0; with addition of a post
                                                                           combustion NOX control the upper
                                                                           range could be reduced significantly.
Long Dry.........................................                    3.0  Limits reviewed showed 5.1; with
                                                                           addition of post combustion NOX
                                                                           control the limit could be reduced
                                                                           significantly; limit of 3.0 would
                                                                           achieve a 41% reduction in NOX
                                                                           emissions.
Preheater........................................                    3.8  Limits reviewed ranged between 1.5-
                                                                           3.44; limit of 3.8 is consistent with
                                                                           30 TAC 117.3110(a)(3) and 35 IAC
                                                                           217.224(a).
Precalciner......................................                    2.3  Requires post combustion NOX control;
                                                                           consistent with permit A0017 for
                                                                           Lehigh Southwest Cement Company
                                                                           issued on May 5, 2020 by the Bay Area
                                                                           Air Quality Management District.
Preheater/Precalciner............................                    2.8  Limits reviewed ranged between 1.8-
                                                                           3.4; limit of 2.8 is consistent with
                                                                           30 TAC 117.3110(a)(4); Mitsubishi
                                                                           Cement Corporation Lucerne Valley
                                                                           Federal Operating Permit 11800001
                                                                           issued by the Mojave Desert Air
                                                                           Quality Management District (MDAQMD)
                                                                           June 18, 2020; MDAQMD Rule 1161
                                                                           (C)(2); and Illinois 35 IAC
                                                                           217.224(a).
----------------------------------------------------------------------------------------------------------------

Although the EPA is proposing NOX emissions limits based on 
the specific kiln types listed in Table VII.C-2, to provide operational 
flexibility the EPA is also proposing a source cap limit expressed in 
tons per day (tpd) of NOX for each individual cement plant 
according to the following equation.
[GRAPHIC] [TIFF OMITTED] TP06AP22.002


Where:

CAP2015 Ozone Transport = total allowable NOX emissions 
from all cement kilns located at one cement plant, in tons per day, 
on a 30-operating day rolling average basis;
KD = 1.7 pounds NOX per ton of clinker for dry preheater-
precalciner or precalciner kilns;
KW = 3.4 pounds NOX per ton of clinker for long wet 
kilns;
ND = the average annual production in tons of clinker plus one 
standard deviation for the three most recent calendar years from all 
dry preheater-precalciner or precalciner kilns located at one cement 
plant; and
NW = the average annual production in tons of clinker plus one 
standard deviation for the three most recent calendar years from all 
long wet kilns located at one cement plant.

    An affected cement plant will need to comply with both the source 
cap limit and the specific NOX emissions limits assigned to 
its individual kiln type(s). The EPA notes that the above source cap 
would be calculated and assigned to operating kilns in a particular 
plant. That is, the total allowable NOX emissions in tpd 
from one plant cannot be traded with another plant, regardless of these 
plants' control of ownership or operator's status, or regardless of 
these plants' proximity to each other or their location.
    The EPA is soliciting comment on whether it is feasible or 
appropriate to phase out and retire existing long wet kilns in the 
affected states and to replace them with more energy efficient and less 
emitting units like preheater/precalciner installations. The EPA is 
also requesting comment on the time needed to complete such a task. It 
has been shown that such kilns replacements (preheater/precalciner 
kilns), when equipped with post-combustion NOX control 
devices such as SNCR, are capable of meeting NOX emissions 
limit of 1.5 lb/ton of clinker on a 30-operating day basis. For this 
reason, the EPA proposes to find that conversion from long wet kilns to 
preheater/precalciner installations is generally feasible. Given that 
long wet kilns are less energy efficient and generally emit more 
NOX than other kiln types, conversion to preheater/
precalciner installations would be the most effective method of 
NOX reduction (per ton of clinker produced).
    Additionally, EPA is soliciting comments on whether it is feasible 
or appropriate to require sources with existing preheater/precalciner 
kilns in the affected states that currently utilize low NOX 
burners, combustion controls, staged combustion, or mid-kiln firing to 
add and operate a post combustion control device like SNCR or SCR to 
further improve their NOX removal efficiency and lower 
NOX emissions to 1.95 lb/ton of clinker or less. The EPA is 
also requesting comments on the time needed to complete such an 
addition. We note that the EPA previously stated that it expects that 
the controls for cement kilns would take at least 2 years to install on 
a sector-wide basis across the 12-state region affected by the Revised 
CSAPR Update.\315\
---------------------------------------------------------------------------

    \315\ 85 FR 68999 (October 30, 2020).
---------------------------------------------------------------------------

Compliance Assurance Requirements
    The EPA is proposing that performance tests be conducted on a 
semiannual basis. Such tests shall be conducted in conformance with the 
requirements of 40 CFR 60.8. Stack tests will need to conform with the 
Test Methods and Procedures in 40 CFR 60 appendix A, or other EPA-
approved (federally enforceable) test methods and procedures.
    The EPA is soliciting comments on whether it is feasible or 
appropriate to require affected units (kilns) to be equipped with CEMS 
to measure and monitor the NOX concentration (emissions 
level) instead of conducting performance tests on semiannual basis.
    We are also soliciting comment on whether it is appropriate for the 
affected units (kilns) to use CPMS instead of CEMS to monitor the 
NOX concentration (emissions level). We note that CPMS, also 
called parametric monitoring, measures a parameter (or multiple 
parameters) as a key indicator of system performance. The parameter is 
generally an operational parameter of the process

[[Page 20145]]

or the air pollution control device (APCD) that is known to affect the 
emissions levels from the process or the control efficiency of the 
APCD. Examples of parametric monitoring include kiln feed rate, clinker 
production rate, fuel type, fuel flow rate, specific heat consumption, 
secondary air temperature, kiln feed-end temperature, preheater exhaust 
gas temperature, induced draught fan pressure drop, kiln feed-end 
percentage oxygen, percentage downcomer oxygen, primary air flow rate, 
ammonia feed rate and slippage.
3. Iron and Steel Mills and Ferroalloy Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the 
Iron and Steel Mills and Ferroalloy Manufacturing source category that 
apply to emissions units that directly emit or have the potential to 
emit 100 tpy or more of NOX and to facilities containing two 
or more such units that collectively emit or have the potential to emit 
100 tpy or more of NOX. The EPA is setting emissions limits 
based on type of unit to ensure that the necessary emissions reductions 
occur across all units of the same type. The EPA is seeking comment on 
whether it should set an applicability threshold based on a unit's 
production capacity rather than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Iron and Steel and 
Ferroalloy Manufacturing industry, the EPA reviewed RACT NOX 
rules, NESHAP rules, air permits and related emissions tests, technical 
support documents, and consent decrees. These rules and source-specific 
requirements most commonly express the emissions limits for this 
industry in terms of mass of pollutant emitted (pounds) per operating 
hour (hours) (i.e., pounds of NOX emitted per production 
hour), pounds per energy unit (i.e., million British thermal unit 
(mmBtu)), or pounds of NOX per ton of steel produced. A 
regulated entity routinely monitors and keeps track of its production 
in terms of tons of steel produced per hour (heat rate) as it pertains 
to the facility's rate of iron and steel production. Depending on the 
type of unit and industry practice, the EPA is proposing rate-based 
emissions limits in the form of lb/mmBtu, production-based limits in 
the form of lb/ton, and work practice standards.
    In determining the averaging times for the limits, EPA initially 
reviewed the NESHAP for Iron and Steel Foundries codified at 40 CFR 
part 63 subpart EEEEE, the NESHAP for Integrated Iron and Steel 
manufacturing facilities codified at 40 CFR part 63 subpart FFFFF, the 
NESHAP for Ferroalloys Production: Ferromanganese and Silicomanganese 
codified at 40 CFR part 63 subpart XXX, and the NESHAP for Ferroalloys 
Production Facilities codified at 40 CFR part 63 subpart YYYYYY. EPA 
also reviewed various RACT NOX rules from states located 
within the OTR, several of which have chosen to implement OTC model 
rules and recommendations. Based on this information, the EPA is 
proposing to require a 30-operating day rolling average period as the 
averaging time frame for this particular industry. The EPA finds that a 
30-operating day rolling average period provides a reasonable balance 
between short term (hourly or daily) and long term (annual) averaging 
periods, while being flexible and responsive to fluctuations in 
operations and production.
    Based on the available information for this industry, applicable 
federal and state rules, and active air permits or enforceable orders 
issued to affected facilities in the iron and steel and ferroalloy 
manufacturing industry, the EPA proposes the following emissions 
limits:

    Table VII.C-3--Summary of Proposed NOX Emissions Limits for Iron and Steel and Ferroalloy Emissions Units
----------------------------------------------------------------------------------------------------------------
                                                Proposed NOX emissions standard or
              Emissions unit                    requirement (lbs/hour or lb/mmBtu)       Additional information
----------------------------------------------------------------------------------------------------------------
Blast Furnace.............................  0.03 lb/mmBtu.............................  OH NOX RACT rules limit
                                                                                         NOX emissions from
                                                                                         blast furnaces to 0.06
                                                                                         lb/mmBtu without
                                                                                         requiring specific
                                                                                         control technology.
                                                                                         Control NOX at stoves
                                                                                         (typically 3 or 4 per
                                                                                         blast furnace),
                                                                                         assuming 40-50%
                                                                                         reduction) by burner
                                                                                         replacement plus SCR.
Basic Oxygen Furnace......................  0.07 lb/ton...............................  Potential 25-50%
                                                                                         reduction by SCR/SNCR
                                                                                         from 0.14 lb/ton based
                                                                                         on emissions testing.
Electric Arc Furnace......................  0.15 lb/ton steel.........................  Example permit limits at
                                                                                         around 0.2 lb/ton.
                                                                                         Assumes 25% reduction
                                                                                         by SCR to achieve 0.15
                                                                                         lb/ton steel.
Ladle/tundish Preheaters..................  0.06 lb/mmBtu.............................  Nucor Kankakee BACT
                                                                                         permit limit issued
                                                                                         January 2021 is 0.1 lb/
                                                                                         mmBtu, 2021. Assume 40%
                                                                                         reduction by SCR.
Reheat furnace............................  0.05 lb/mmBtu.............................  Sterling Steel permit,
                                                                                         issued 2019: Low-NOX
                                                                                         natural gas fired
                                                                                         burners designed to
                                                                                         emit no more than 0.073
                                                                                         lb NOX/mmBtu, Ohio RACT
                                                                                         limit is 0.09 lb/mmBtu.
                                                                                         Assume 40% reduction by
                                                                                         SCR.
Annealing Furnace.........................  0.06 lb/mmBtu.............................  Big River Steel (AR)
                                                                                         2018 limit and Benteler
                                                                                         Steel (LA) 2019 limit
                                                                                         (0.11 lb/mmBtu), 85
                                                                                         mmBtu/hr and 13 mmBtu/
                                                                                         hr, respectively.
                                                                                         Lowest was 0.0915 lb/
                                                                                         mmBtu, Nucor AR. Assume
                                                                                         40% reduction by SCR.
Vacuum Degasser...........................  0.03 lb/mmBtu.............................  0.05 lb/mmBtu Nucor
                                                                                         Darlington (SC) and
                                                                                         Nucor Tuscaloosa (AL).
                                                                                         Assume 40% reduction by
                                                                                         SCR.
Ladle Metallurgy Furnace..................  0.1 lb/ton................................  Assume 40% reduction by
                                                                                         SCR.
Taconite Production Kilns.................  Work practice standard to install and       Consistent with
                                             operate low NOX burners.                    requirements in
                                                                                         Minnesota Taconite FIP
                                                                                         See 81 FR 21671.
Coke Ovens (charging).....................  0.15 lb/ton of coal charged...............  Assume 50% reduction
                                                                                         staged combustion and/
                                                                                         or limited use SCR/SNCR
                                                                                         during charging
                                                                                         operations from AP-42
                                                                                         0.3 lb/ton emission
                                                                                         factor.
Coke Ovens (pushing)......................  0.015 lb/ton of coal pushed...............  SunCoke Middletown limit
                                                                                         is 0.02 lb/ton of coal.
                                                                                         Assume 25% reduction by
                                                                                         SCR.
Boilers--Coal.............................  0.20 lb/mmBtu.............................  See explanation in
                                                                                         Section VII.C.5.
Boilers--Residual oil.....................  0.20 lb/mmBtu.............................  See explanation in
                                                                                         Section VII.C.5.
Boilers--Distillate oil...................  0.12 lb/mmBtu.............................  See explanation in
                                                                                         Section VII.C.5.

[[Page 20146]]

 
Boilers--Natural gas......................  0.08 lb/mmBtu.............................  See explanation in
                                                                                         Section VII.C.5.
----------------------------------------------------------------------------------------------------------------

    Due to the many types of units within Iron and Steel Mills and 
Ferroalloy Manufacturing facilities that are not currently subject to 
NOX limitations of the stringency necessary to eliminate 
significant contribution, most of the emissions limits in this proposed 
rule are based on examples of permitted emissions and estimated 
reduction potential from the identified control technology. Based on 
the selection of SCR, SNCR, and burner replacement in the non-EGU 
screening assessment, the EPA assumed reductions of 20 to 50 percent 
from current permitted limits and emissions tests depending on the type 
of unit and controls being implemented.
    In addition, for Taconite Production Kilns, the EPA does not 
currently have the data to determine appropriate emissions limits that 
these units could achieve by installing low NOX burners. 
Therefore, the EPA is proposing to require the installation of low 
NOX burners for Taconite Production Kilns and work practice 
standards for operating these control technologies to achieve emissions 
reductions. The EPA is also proposing to require these sources to 
perform performance tests and establish a unit-specific emissions limit 
at that time. These work practice standards are consistent with EPA's 
Taconite FIP for Minnesota. See 81 FR 21671 (April 12, 2016). Due to 
the ongoing nature of this FIP, the EPA is proposing to require 
installation of specific control technologies and a period of 
evaluation before setting a numerical emissions limit.
Compliance Assurance Requirements
    The EPA is proposing to require each owner or operator of an 
affected facility that is subject to the NOX emissions limit 
for Iron and Steel Mills and Ferroalloy Manufacturing emissions units 
contained in this section to install, calibrate, maintain, and operate 
a CEMS for the measurement of NOX emissions discharged into 
the atmosphere from the affected facility. The EPA is proposing that 
each emissions unit will be required to conduct an initial performance 
test and to operate CEMS to assure compliance. In conducting the 
performance tests to demonstrate compliance, sources must use test 
methods and procedures in 40 CFR 60 appendix A, Method 7E, or other 
EPA-approved (federally enforceable) test methods and procedures. The 
EPA is also soliciting comments on alternative monitoring systems or 
methods that are equivalent to CEMS to demonstrate compliance with the 
emissions limits.
4. Glass and Glass Product Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the 
Glass and Glass Product Manufacturing source category that apply to 
emissions units that directly emit or have the potential to emit 100 
tpy or more of NOX. The EPA is setting emissions limits 
based on type of unit to ensure that the necessary emissions reductions 
occur. The EPA is seeking comment on whether it should set an 
applicability threshold based on a unit's production capacity rather 
than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Glass and Glass Product 
Manufacturing industry, the EPA reviewed RACT NOX rules, air 
permits, Alternative Control Techniques (ACT), and consent decrees. 
These rules and source-specific requirements most commonly express the 
emissions limits for this industry in terms of mass of pollutant 
emitted (pounds) per weight of glass removed from the furnace (tons), 
i.e., pounds of NOX emitted per ton of glass produced. A 
regulated entity routinely monitors and keeps track of its glass 
outputs as it pertains to a furnace's design capacity and the plant's 
production. Therefore, the EPA believes that this form of 
NOX emissions limit is effective, practicable, and 
convenient to record and report to an air agency.
    In determining the averaging time for the limits, the EPA initially 
reviewed the NSPS for glass manufacturing plants codified at 40 CFR 
part 60 subpart CC. This NSPS applied to any glass melting furnace in 
an affected facility that commenced construction or modification after 
June 15, 1979, and produced more than 5 tons of glass per day. It was 
noted that the NSPS only provides standards for particulate matter and 
does not provide standards or averaging times for NOX. In 
order to determine the averaging time for the NOX emissions 
limits, the EPA reviewed various RACT NOX rules from states 
located within the OTR, several of which have chosen to implement OTC 
model rules and recommendations.
    Most of the states within the OTR implement RACT regulations for 
the glass manufacturing industry that do not specify presumptive 
NOX limits.\316\ With respect to those RACT rules in the OTR 
states that contain presumptive RACT NOX limits for glass 
manufacturing furnaces, EPA found variations in averaging times, 
ranging from a 30-day rolling average to a more stringent daily 
average.\317\ The EPA also reviewed RACT NOX regulations for 
the glass manufacturing industry outside the OTR and observed that 30-
day rolling averages and daily averages varied throughout the 
states.\318\ The EPA is proposing to require owners or operators of 
glass manufacturing furnaces to comply with the applicable presumptive 
NOX emissions limits on a 30-day rolling average time frame. 
This averaging time frame is consistent with other statewide RACT 
NOX regulations for this particular industry. Furthermore, a 
state's air agency may choose to require an averaging period shorter 
than a 30-operating day rolling

[[Page 20147]]

average in air permits or RACT regulations for these plants. The EPA 
finds that a 30-operating day rolling average period provides a 
reasonable balance between short term (hourly or daily) and long term 
(annual) averaging periods, while being flexible and responsive to 
fluctuations in operation and production.
---------------------------------------------------------------------------

    \316\ RACT NOX rules of the following OTR states CT, 
DC, DE, MD, ME, NH, NY, RI, VA, and VT do not provide presumptive 
NOX limits for glass manufacturing sources. These RACT 
regulations require owners or operators to submit RACT case-by-case 
analysis.
    \317\ Pennsylvania's presumptive RACT NOX emissions 
limits are based on 30-day rolling average. New Jersey's and 
Massachusetts' rules contain more stringent daily averages. 
Maryland's RACT rule, section 26.11.09.08.I, requires owner or 
operators to optimize combustion by performing daily oxygen tests 
and maintain excess oxygen at 4.5% or less. See http://www.dsd.state.md.us/comar/comarhtml/26/26.11.09.08.htm.
    \318\ For example, presumptive RACT NOX emissions 
limits in California are based on both 30-day rolling and daily 
averages (see https://www.valleyair.org/rules/currntrules/R4354%20051911.pdf). Wisconsin's NOX emissions limits are 
based on a 30-day rolling average (see https://casetext.com/regulation/wisconsin-administrative-code/agency-department-of-natural-resources/environmental-protection-air-pollution-control/chapter-nr-428-control-of-nitrogen-compound-emissions/subchapter-iv-NOX-reasonably-available-control-technology-requirements/section-nr-
42822-emission-limitation-requirements).
---------------------------------------------------------------------------

    Based on the available information for this industry, applicable 
state and local air agency rules, and active air permits or enforceable 
orders issued to affected glass manufacturing plants, EPA is proposing 
the following emissions limits for glass manufacturing furnaces:

    Table VII.C-4--Summary of Proposed NOX Emissions Limits for Furnace Unit Types in Glass and Glass Product
                                                  Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                  Proposed NOX
                                                emissions limit
                 Furnace type                   (lb/ton of glass              Additional information
                                                   produced)
----------------------------------------------------------------------------------------------------------------
Container Glass Manufacturing Furnace........                4.0  Limits reviewed ranged between 1-4; one state
                                                                   rule allowed as high as 5; with addition of
                                                                   post combustion NOX controls, the upper range
                                                                   could be reduced significantly; consistent
                                                                   with 25 Pennsylvania Code 129.304(a)(1) and
                                                                   New Jersey Administrative Code 7:27
                                                                   Subchapter 19.1.
Pressed/Blown Glass Manufacturing Furnace or                 4.0  Limits reviewed ranged between 1.36-4; one
 Fiberglass Manufacturing Furnace.                                 state rule allowed as high as 7; with
                                                                   addition of post combustion control the limit
                                                                   could be reduced significantly; limit of 4.0
                                                                   is consistent with RACT regulations for
                                                                   states located within OTR.
Flat Glass Manufacturing Furnace.............                9.2  Limits reviewed ranged between 5-9.2; with the
                                                                   addition of post combustion controls the
                                                                   limit could be reduced significantly;
                                                                   consistent with San Joaquin Valley Air
                                                                   Pollution Control District Rule 4354 5.1.1
                                                                   and New Jersey Administrative Code 7:27
                                                                   Subchapter 19.1.
----------------------------------------------------------------------------------------------------------------

    The EPA is soliciting comment on whether it is feasible or 
appropriate to phase out and retire existing glass manufacturing 
furnaces in the affected states and replace them with more energy 
efficient and less emitting units like all-electric melter 
installations. The EPA is also requesting comment on the time needed to 
complete such a task. All-electric melters are glass melting furnaces 
in which all the heat required for melting is provided by electric 
current from electrodes submerged in the molten glass.\319\ All-
electric melter furnaces could provide an energy efficient and 
NOX emission-free alternative to current methods of melting 
and producing glass.
---------------------------------------------------------------------------

    \319\ See definitions in 40 CFR part 60 subpart CC.
---------------------------------------------------------------------------

    According to the EPA's ``Alternative Control Techniques Document--
NOX Emissions from Glass Manufacturing,'' \320\ glass 
manufacturing furnaces may utilize combustion modifications equivalent 
to low-NOX burners and oxy-firing. The EPA is soliciting 
comment on whether it is feasible or appropriate to require sources 
with existing glass manufacturing furnaces in affected states that 
currently utilize these combustion modifications to add and operate a 
post-combustion control device like SNCR and SCR to further improve 
their NOX removal efficiency. The EPA is also requesting 
comments on the time needed to install such controls.
---------------------------------------------------------------------------

    \320\ ``Alternative Control Techniques Document--NOX 
Emissions from Glass Manufacturing,'' EPA-453/R-94-037, June 1994.
---------------------------------------------------------------------------

Compliance Assurance Requirements
    The EPA is proposing to require each owner or operator of an 
affected facility that is subject to the NOX emissions 
standards for glass manufacturing furnaces contained in this section to 
install, calibrate, maintain, and operate a CEMS for the measurement of 
NOX emissions discharged into the atmosphere from the 
affected facility. The EPA is also soliciting comments on alternative 
monitoring systems or methods that are equivalent to CEMS to 
demonstrate compliance with the emissions limits. In conducting the 
performance tests to demonstrate compliance, sources must use test 
methods and procedures in 40 CFR part 60 appendix A, method 7E, or 
other EPA-approved (federally enforceable) methods and procedures. 
Owners or operators must calculate and record the 30-operating day 
rolling emissions rate of NOX as the total of all hourly 
emissions data for a glass manufacturing furnace in the preceding 30 
days, divided by the total tons of glass produced in that furnace 
during the same 30-operating day period. Owners or operators of glass 
manufacturing furnaces installed with continuous emissions monitoring 
may demonstrate compliance with the emissions limit as follows: (1) 
Determine the average pounds of NOX emitted per day, (2) 
determine the tons of glass removed per day during the same day, (3) 
divide the average pounds of NOX emitted per day by the tons 
of glass removed per day as determined in step (2), and (4) compare the 
quotient to the emissions limits prescribed in the Section VII of this 
proposed rule. If the pollutant mass emissions rate is in lb/hr, the 
following equation \321\ shall be used to convert the emissions rate to 
lb pollutant/ton of glass pulled:
---------------------------------------------------------------------------

    \321\ This equation is provided in the San Joaquin Valley 
Unified Air Pollution Control District's Rule 4354, section 8.1.
[GRAPHIC] [TIFF OMITTED] TP06AP22.003


[[Page 20148]]


5. Boilers From Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, and Pulp, Paper, and Paperboard Mills
Applicability
    The EPA is proposing to establish regulatory requirements for the 
Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills industries that 
apply to boilers within these facilities that have a design capacity of 
100 mmBtu/hr or greater. These requirements are consistent with EPA's 
findings at Step 3 with respect to Tier 2 non-EGU industries. As noted 
below, we do not believe boilers meeting this size classification exist 
within the other Tier 2, or Tier 1 industries, but if they do, the EPA 
proposes that they would also be subject to the requirements of this 
part. Based on our review of the potential emissions from industrial 
boilers of various fuel types, we find that use of a boiler design 
capacity of 100 mmBtu/hr reasonably approximates the selection of 100 
tpy used within the Non-EGU Screening Assessment memorandum. Therefore, 
boilers subject to the requirements of this section of the proposed 
rule are those found within any of the 23 covered states with non-EGU 
emissions reduction obligations that are within a Tier 1 or Tier 2 
industry and have a design capacity of 100 mmBTU/hr or greater. The EPA 
is seeking comment on whether EPA should alternatively set an 
applicability threshold based on potential to emit.
Emissions Limitations and Rationale
    This section of the proposed rule applies to certain boilers 
located at any facility identified as a Tier 2 industry within the non-
EGU screening assessment. As described within the Non-EGU Screening 
Assessment memorandum, the EPA reviewed the projected 2026 emissions 
data to identify large boilers within the Tier 2 industries, defined as 
boilers projected to emit more than 100 tons per year in 2026. Boilers 
meeting this threshold were found in three of the five Tier 2 
industries, as identified in Table VII.C.5-1.

  Table VII.C.5-1--Tier 2 Industries With Large Boilers and Associated
                               NAICS Codes
------------------------------------------------------------------------
                                                                  NAICS
                            Industry                               code
------------------------------------------------------------------------
Basic Chemical Manufacturing...................................   3251xx
Petroleum and Coal Products Manufacturing......................   3241xx
Pulp, Paper, and Paperboard Mills..............................   3221xx
------------------------------------------------------------------------

    The EPA did not find large boilers within the Lime and Gypsum 
Product Manufacturing (NAICS code 3274xx) or the Metal Ore Mining 
industries (NAICS code 2122xx). As such the EPA is not expressly 
proposing to include boilers in those industries. However, if as a 
result of receiving additional information during the comment period 
the EPA identifies large boilers within these two industries that meet 
the applicability criteria described below, those boilers could be 
subject to the requirements of the final rule.
    As described within the Non-EGU Sectors TSD, the RACT rules we 
reviewed containing NOX limits for industrial boilers relied 
primarily on design capacity in mmBtu/hr as the metric for selecting 
design criteria. The EPA is proposing to use that same metric to 
establish control requirements for boilers with a design capacity of 
100 mmBtu/hr or greater. As noted within the Non-EGU Sectors TSD, 
boilers rated at 100 mmBtu/hr or greater can emit large amounts of 
NOX, particularly if they do not operate NOX 
control equipment.
    The EPA reviewed NOX emissions limits for industrial 
boilers with design capacities of 100 mmBtu/hr or greater that have 
been adopted by states and incorporated into their SIPs. The Non-EGU 
Sectors TSD contains a detailed discussion of that evaluation. Based on 
our review, we propose to establish the following NOX 
emissions limits for coal, oil, and gas fired industrial boilers 
located at a Tier 2 industry:

               Table VII.C.5-2--Proposed NOX Emissions Limits for Industrial Boilers >100 mmBtu/hr
----------------------------------------------------------------------------------------------------------------
                                           Emissions limit
               Unit type                   (lbs NOX/mmBtu)                  Additional information
 
----------------------------------------------------------------------------------------------------------------
Coal...................................               0.20   Limits reviewed ranged from 0.08 to 1.0. Proposed
                                                              limit will likely require a combination of
                                                              combustion controls or post-combustion controls.
Residual oil...........................               0.20   Limits reviewed ranged from 0.15 to 0.50. Proposed
                                                              limit will likely require combustion controls.
Distillate oil.........................               0.12   Limits reviewed ranged from 0.10 to 0.43. Proposed
                                                              limit will likely require combustion controls.
Natural gas............................               0.08   Limits reviewed ranged from 0.06 to 0.25.
                                                             Proposed limit will likely require a combination of
                                                              combustion controls or post-combustion controls.
----------------------------------------------------------------------------------------------------------------

Additional information on the EPA's derivation of these proposed 
emissions rates for boilers is provided below and in the Non-EGU 
Sectors TSD.
    The EPA notes that some coal, oil, and gas-fired industrial boilers 
may have already installed combustion or post-combustion control 
equipment, such as SCR or SNCR, sufficient to meet the emission limits 
established in this FIP. Some of the boilers covered by this FIP might 
have install controls to meet the emission limits contained within 
EPA's NSPS located at 40 CFR 60 Subpart Db, which requires that some 
fossil fuel-fired units that commenced construction, modification, or 
reconstruction after June 19, 1984, meet various NOx 
emission limits based on factors such as unit type or heat rate. 
Additionally, industrial boilers located in ozone nonattainment areas 
or within the ozone transport region may have installed controls to 
meet emission limits adopted by states to meet NOx RACT 
requirements.
a. Coal-Fired Industrial Boilers
    Coal-fired industrial boilers subject to the proposed requirements 
of this section would have to meet a NOX emissions limit of 
0.2 lbs/mmBtu on a 30-day rolling average basis.
    Various forms of combustion and post-combustion NOX 
control technology exist that should enable most facilities to be 
retrofit with equipment that will enable them to meet these emissions 
limits. Additionally, as noted in the Non-EGU Sectors TSD, many states 
containing ozone nonattainment areas or located within the OTR have 
already adopted emissions limits similar to or more stringent than the 
limits the EPA proposes here. Furthermore, some coal-fired industrial 
boilers may have installed combustion or post-combustion control 
equipment to meet the emissions limits contained within EPA's NSPS 
located at 40 CFR part 60 subpart Db, which requires that coal-fired 
industrial boilers meet a NOX emissions limit of between 0.5 
and 0.8

[[Page 20149]]

lbs/mmBtu depending on unit type.\322\ Enhancements to or retrofit of 
additional NOX control technology should enable most sources 
to meet the proposed NOX limit.
---------------------------------------------------------------------------

    \322\ 40 CFR 60.44b.
---------------------------------------------------------------------------

    There are two main types of NOX control technology that 
we believe can be retrofit to most existing industrial boilers, or 
incorporated into the design of new boilers, to meet our proposed 
emissions limits. These two control types are combustion controls and 
post-combustion controls, and in some instances both types are used 
together. As noted in the EPA's ``Alternative Control Techniques 
Document--NOX Emissions from Industrial/Commercial/
Institutional (ICI) Boilers'' (hereafter ``ICI Boiler ACT''),\323\ the 
type of NOX control available for use on a particular unit 
depends primarily on the type of boiler, fuel type, and fuel-firing 
configuration. For example, Table 2-3 of the ICI Boiler ACT indicates 
which types of combustion and post-combustion NOX controls 
are suitable to various types of coal-fired ICI boilers. We note that 
one type of combustion control, staged combustion air, and one type of 
post-combustion control, SNCR, are indicated as being compatible with 
all coal-fired unit types. Additional resources are available that 
document the availability of NOX control equipment for 
industrial boilers.\324\
---------------------------------------------------------------------------

    \323\ ``Alternative Control Techniques Document--NOX 
Emissions from Industrial/Commercial/Institutional (ICI) Boilers,'' 
EPA-453/R-94-022, March 1994.
    \324\ For example, see ``Applicability and Feasibility of 
NOX, SO2, and PM Emissions Control 
Technologies for Industrial, Commercial, and Institutional 
Boilers,'' Northeast States for Coordinated Air Use Management, 
November 2008 (revised January 2009) and ``Nitrogen Oxides 
(NOx), Why and How They Are Controlled,'' EPA, Clean Air 
Technical Center, 456/F-99-006R, November 1999.
---------------------------------------------------------------------------

b. Oil-Fired Industrial Boilers
    Most oil-fired boilers are fueled by either residual (heavy) oil or 
distillate (light) oil. The proposed NOX emissions limit for 
residual oil-fired boilers subject to the requirements of this section 
is 0.2 lbs/mmBtu, and the proposed emissions limit for distillate oil-
fired boilers is 0.12 lbs/mmBtu. The proposed averaging time for these 
emissions limits is a 30-day rolling average. As with coal-fired 
industrial boilers, a number of combustion and post-combustion 
NOX control technologies exist that should enable most 
facilities to meet these emissions limits, and the Non-EGU Sectors TSD 
identifies numerous states that have already adopted emissions limits 
similar to the limits EPA proposes here. Table 2-3 of the ICI Boiler 
ACT indicates that two types of NOX combustion control, low-
NOX burners and flue gas recirculation, are commonly found 
on oil-fueled industrial boilers, and that SNCR, a post-combustion 
control technology, is suitable to most oil-fueled industrial boilers 
other than those of the packaged firetube design. Some oil-fired 
industrial boilers may have already installed combustion or post-
combustion control equipment to meet the emissions limits contained 
within EPA's NSPS at 40 CFR part 60 subpart Db, which requires that 
distillate oil-fired units meet a NOX emissions limit of 
between 0.1 to 0.2 lbs/mmBtu depending on heat release rate, and that 
residual oil-fired units meet a NOX emissions limit of 
between 0.3 to 0.4 lbs/mmBtu also depending on heat release rate.\325\ 
The additional resources noted in the paragraph above discussing coal-
fired industrial boilers also contain useful information regarding 
effective NOX control equipment for residual and distillate 
fueled industrial boilers.
---------------------------------------------------------------------------

    \325\ 40 CFR 60.44b.
---------------------------------------------------------------------------

c. Gas-Fired Industrial Boilers
    The proposed NOX emissions limit for gas-fired boilers 
subject to the requirements of this section is 0.08 lbs/mmBtu. The 
proposed averaging time for these emissions limits is a 30-day rolling 
average.
    As with fossil-fuel-fired boilers, numerous combustion and post-
combustion NOX control technologies exist that should enable 
most facilities to meet these emissions limits, and many states have 
already adopted emissions limits similar to the limits the EPA proposes 
here. Table 2-3 of the ICI Boiler ACT indicates the same control 
technologies that are suitable for application to oil-fired boilers are 
also likely to be effective at controlling NOX emissions 
from gas-fired industrial boilers. Some gas-fired industrial boilers 
may have already installed combustion or post-combustion control 
equipment to meet the emissions limits contained within EPA's NSPS at 
40 CFR 60 Subpart Db, which requires that gas-fired units meet a 
NOX emissions limit of between 0.1 to 0.2 lbs/MMBtu 
depending on heat release rate. The additional resources noted in the 
discussion of coal-fired industrial boilers also contain useful 
information regarding effective NOX control equipment for 
gas-fired industrial boilers.
    The EPA anticipates that the majority of boilers covered by this 
section of the FIP will combust one of the fuels for which we have 
proposed emissions limits. However, we request comment on whether 
emissions limits for other types of fuels should be included in a final 
FIP, and if so, the types of fuels and the emissions limits that 
boilers powered by these fuels should be required to meet. 
Additionally, the EPA seeks comment on whether the EPA should establish 
less stringent emissions rates for boilers with low utilization rates, 
and if so, the appropriate emissions rate(s) and corresponding boiler 
utilization rate(s). The EPA also seeks comment on whether a different 
averaging time other than the 30-day averaging time proposed for 
boilers would be more appropriate and requests information supporting 
any suggested alternative.
Compliance Assurance Requirements
    Given the similarities in the types of units covered, the EPA 
proposes that boilers subject to the requirements of this section 
demonstrate compliance in a manner similar to the emissions monitoring 
requirements found in section 60.45 of the NSPS for industrial, 
commercial, and institutional (ICI) boilers at 40 CFR part 60 subpart 
D. Those requirements include, among other provisions, the performance 
of an initial compliance test, installation of a CEMS unless the 
initial performance test indicates the unit's emissions rate is 70 
percent or less of the required emissions rate, and an annual stack 
test for units not required to install a CEMS.

D. Submitting a SIP

    A state may submit a SIP at any time to address CAA requirements 
that are covered by a FIP, and if the EPA approves the SIP it would 
replace the FIP, in whole or in part, as appropriate.\326\ The EPA has 
established certain specialized provisions for replacing FIPs with SIPs 
within all the CSAPR trading programs, including the use of so-called 
``abbreviated SIPs'' and ``full SIPs,'' see 40 CFR 52.38(a)(4) and (5) 
and (b)(4), (5), (8), (9), (11), and (12); 40 CFR 52.39(e), (f), (h), 
and (i). For a state to remove all FIP provisions through an approved 
SIP revision, a state would need to address all of the required 
reductions addressed by the FIP for that state, i.e., reductions 
achieved through both EGU control and non-EGU control, as applicable to 
that state. Additionally, tribes in Indian country within the 
geographic scope of this proposed rule may elect to work with EPA under 
the Tribal Authority Rule to replace the FIP for areas of Indian 
country, in whole or in part, with a tribal implementation plan or

[[Page 20150]]

reasonably severable portions of a tribal implementation plan.
---------------------------------------------------------------------------

    \326\ CAA sections 110(c)(1)(B), 110(k)(3).
---------------------------------------------------------------------------

    Under the proposed new FIPs for the 25 states whose EGUs would be 
required to participate in the CSAPR NOX Ozone Season Group 
3 Trading Program with its proposed modifications, ``abbreviated'' and 
``full'' SIP options continue to be available. An ``abbreviated SIP'' 
allows a state to submit a SIP revision that would establish state-
determined allowance allocation provisions replacing the default FIP 
allocation provisions but leaves the remaining FIP provisions in place. 
A ``full SIP'' allows a state to adopt a trading program meeting 
certain requirements that would allow sources in the state to continue 
to use the EPA-administered trading program through an approved SIP 
revision, rather than a FIP. In addition, as under past CSAPR 
rulemakings, the EPA proposes to provide states with an opportunity to 
adopt state-determined allowance allocations for existing units for the 
second control period under this rule--in this case, the 2024 control 
period--through streamlined SIP revisions. See 76 FR 48326-48332 for 
additional discussion of full and abbreviated SIP options; see also 40 
CFR 52.38(b).
1. SIP Option To Modify Allocations for 2024 Under EGU Trading Program
    As with the start of past CSAPR rulemakings, the EPA proposes to 
allow a state to use a similar process to submit a SIP revision 
establishing allowance allocations for existing EGU units in the state 
for the second control period of the new requirements, i.e., in 2024, 
to replace the EPA-determined default allocations. This proposed 
process would use updated deadlines, i.e., a state must submit a letter 
to EPA within 60 days of publication of the final rule indicating its 
intent to submit a complete SIP revision by September 1, 2023. The SIP 
would provide in an EPA-prescribed format a list of existing units 
within the state and their allocations for the 2024 control period. If 
a state does not submit a letter of intent to submit a SIP revision, 
the EPA-determined default allocations will be recorded by 90 days of 
publication of the final rule. If a state submits a timely letter of 
intent but fails to submit a SIP revision, the EPA-determined default 
allocations will be recorded by September 15, 2023. If a state submits 
a timely letter of intent followed by a timely SIP revision that is 
approved, the approved SIP allocations will be recorded by March 1, 
2024.
    The EPA requests comment on the proposed option to modify allowance 
allocations under the Group 3 trading program for EGUs for the 2024 
control period through a SIP revision.
2. SIP Option To Modify Allocations for 2025 and Beyond Under EGU 
Trading Program
    For the 2025 control period and later, the EPA proposes that states 
in the CSAPR NOX Ozone Season Group 3 Trading Program can 
modify the EPA-determined default allocations with an approved SIP 
revision. For the 2025 control period and later, SIPs can be full or 
abbreviated SIPs. States will also have the option to expand 
applicability to include EGUs between 15 MWe and 25 MWe or, in the case 
of states subject to the NOX SIP Call, as discussed in 
Section VII.F.1 of this proposed rule, large non-EGU boilers and 
combustion turbines. Inclusion of the large non-EGUs would serve as a 
mechanism to address the state's outstanding regulatory obligations 
under the NOX SIP Call with respect to those sources, and 
the state would be allowed to allocate a defined quantity of additional 
Group 3 allowances because of the expanded set of sources. See above 
and 76 FR 48326-48332 for additional discussion of full and abbreviated 
SIP options; see also 40 CFR 52.38(b).
    For states that want to modify the EPA-determined default 
allocations or expand applicability of the EGU trading program, the EPA 
proposes that a state could submit a SIP revision that makes changes 
only to one or both of those type of provisions while relying on the 
FIP for the remaining provisions of the EGU trading program. This 
abbreviated SIP option allows states to tailor the FIP to their 
individual choices while maintaining the FIP-based structure of the 
trading program. In order to ensure the availability of allowance 
allocations for units in any Indian country within a state not covered 
by the state's CAA implementation planning authority, if the state 
chose to replace EPA's default allocations with state-determined 
allocations, the EPA would continue to administer any portion of each 
state emissions budget reserved as a new unit set-aside or an Indian 
country existing unit set-aside.
    The proposed SIP submittal deadline for this type of revision is 
December 1, 2023, if the state intends for the SIP revision to be 
effective beginning with the 2025 control period. For states that 
submit this type of SIP revision, the EPA proposes that the deadline to 
submit state-determined allocations beginning with the 2025 control 
period under an approved SIP would be June 1, 2024, and the deadline 
for the EPA to record those allocations would be July 1, 2024. 
Similarly, under the proposed new deadlines a state could submit a SIP 
revision beginning with the 2026 control period and beyond by December 
1, 2024, with state allocations for the 2026 control period due June 1, 
2025, and the EPA recordation of the allocations by July 1, 2025.
    The EPA requests comment on the proposed option to replace certain 
allowance allocation or applicability provisions under the Group 3 
trading program for EGUs for control periods in 2025 and later years 
through a SIP revision.
3. SIP Option To Replace the Federal EGU Trading Program With an 
Integrated State EGU Trading Program
    For the 2025 control period and later, the EPA proposes that states 
in the CSAPR NOX Ozone Season Group 3 Trading Program can 
choose to replace the Federal EGU trading program with an integrated 
State EGU trading program through an approved SIP revision. Under this 
option, a state would submit a SIP revision that makes changes only to 
modify the EPA-determined default allocations or expand applicability 
of the EGU trading program and adopt identical provisions for the 
remaining portions of the EGU trading program. This SIP option allows 
states to replace these FIP provisions with state-based SIP provisions 
while continuing participation in the larger regional trading program. 
As with the abbreviated SIP option discussed above, in order to ensure 
the availability of allowance allocations for units in any Indian 
country within a state not covered by the state's CAA implementation 
planning authority, if the state chose to replace EPA's default 
allocations with state-determined allocations, EPA would continue to 
administer any portion of each state emissions budget reserved as a new 
unit set-aside or an Indian country existing unit set-aside.
    Proposed deadlines for this type of SIP revision are the same as 
the deadlines for abbreviated SIP revisions. For the SIP-based program 
to start with the 2025 control period, the SIP deadline would be 
December 1, 2023, the deadline to submit state-determined allocations 
for the 2025 control period under an approved SIP would be June 1, 
2024, and the deadline for the EPA to record those allocations would be 
July 1, 2024, and so on.
    The EPA requests comment on the proposed option to replace the 
federal trading program for EGUs with an integrated state trading 
program for EGUs for control periods in 2025 and later years through a 
SIP revision.

[[Page 20151]]

4. SIP Revisions That Do Not Use the New Trading Program
    States can submit SIP revisions to replace the FIP that achieve the 
necessary EGU emissions reductions but do not use the CSAPR 
NOX Ozone Season Group 3 Trading Program. For a transport 
SIP revision that does not use the CSAPR NOX Ozone Season 
Group 3 Trading Program, the EPA would evaluate the transport SIP based 
on the particular control strategies selected and whether the 
strategies as a whole provide adequate and enforceable provisions 
ensuring that the necessary emissions reductions (i.e., reductions 
equal to or greater than what the Group 3 trading program will achieve) 
will be achieved. In order to address the applicable CAA requirements, 
the SIP revision should include the following general elements: (1) A 
comprehensive baseline 2023 statewide NOX emissions 
inventory (which includes existing control requirements), which should 
be consistent with the 2023 emissions inventory that the EPA used to 
calculate the required state budget in this final proposed rule (unless 
the state can explain the discrepancy); (2) a list and description of 
control measures to satisfy the state emissions reduction obligation 
and a demonstration showing when each measure would be implemented to 
meet the 2023 and successive control periods; (3) fully-adopted state 
rules providing for such NOX controls during the ozone 
season; (4) for EGUs greater than 25 MWe, monitoring and reporting 
under 40 CFR part 75, and for other units, monitoring and reporting 
procedures sufficient to demonstrate that sources are complying with 
the SIP (see 40 CFR part 51 subpart K (``source surveillance'' 
requirements)); and (5) a projected inventory demonstrating that state 
measures along with federal measures will achieve the necessary 
emissions reductions in time to meet the 2023 and successive compliance 
deadlines (e.g., enforceable reductions commensurate with installation 
of SCR on coal-fired EGUs by the 2026 ozone season). The SIPs must meet 
procedural requirements under the Act, such as the requirements for 
public hearing, be adopted by the appropriate state board or authority, 
and establish by a practically enforceable regulation or permit(s) a 
schedule and date for each affected source or source category to 
achieve compliance. Once the state has made a SIP submission, the EPA 
will evaluate the submission(s) for completeness before acting on the 
SIP. EPA's criteria for determining completeness of a SIP submission 
are codified at 40 CFR part 51 appendix V.
    For further information on replacing a FIP with a SIP, see the 
discussion in the final CSAPR rulemaking (76 FR 48326).
5. SIP Revision Requirements for Non-EGU Emissions Limits
    EPA's promulgation of a non-EGU transport FIP would in no way 
affect the ability of states to submit, for review and approval, a SIP 
that replaces the requirements of the FIP with state requirements. In 
order to replace the non-EGU portion of the FIP in a state, the state's 
SIP must provide adequate provisions to prohibit an equivalent or 
greater amount of NOX emissions that contribute 
significantly to nonattainment or interfere with maintenance of the 
2015 ozone NAAQS in any other state. The non-EGU requirements of the 
FIP would remain in place in each covered state until a state's SIP has 
been approved by the EPA to replace the FIP.
    After promulgation of the final FIP, the EPA anticipates that the 
most straightforward method for a state to submit a SIP revision to 
replace the non-EGU portion of the FIP for the state would be to 
provide a SIP that includes emissions limits at an equivalent or 
greater level of stringency than is specified for non-EGU sources 
meeting the applicability criteria and associated compliance assurance 
provisions for each of the unit types identified in Section VII.C of 
this proposed rule.
    The EPA seeks comment on other potential methods by which states 
could develop a SIP to obtain emissions reductions from non-EGU sources 
that would replace the state's non-EGU portion of the FIP. The EPA 
recognizes that states may select emissions reductions strategies that 
differ from the emissions limitations included in the proposed non-EGU 
FIP. But the state must still demonstrate that the replacement SIP 
provides an equivalent or greater amount of emissions reductions as the 
proposed FIP. The EPA anticipates that such emissions reductions 
strategies would have to achieve reductions beyond those emissions 
reductions already projected to occur in EPA's emissions projections 
and air quality modeling conducted at Steps 1 and 2. Such reductions 
must also be achieved on the same timeframe as the reductions that 
would be required in a final FIP. A demonstration of equivalency using 
other control strategies is complicated by the fact that the proposed 
emissions limits for non-EGU sources are generally rate-based and 
expressed in a variety of forms; this will make comparative analysis to 
determine equivalency challenging.
    In all cases, a SIP submitted by a state to replace the non-EGU 
FIPs would need to rely on permanent and practically enforceable 
controls measures that are included in the SIP and, once approved by 
the EPA, rendered federally enforceable. So-called ``demonstration-
only'' or ``non-regulatory'' SIPs would be insufficient. Further, the 
EPA anticipates that states would bear the burden of establishing that 
the state's alternative approach achieves at least an equivalent level 
of emissions reduction as the FIP, and (unless merely adopting directly 
the control requirements of the FIP) the state would need to provide a 
Step 3 multifactor analysis that the state's SIP eliminates significant 
contribution.

E. Title V Permitting

    This proposed rule, like CSAPR, the CSAPR Update, and the Revised 
CSAPR Update does not establish any permitting requirements independent 
of those under Title V of the CAA and the regulations implementing 
Title V, 40 CFR parts 70 and 71.\327\ All major stationary sources of 
air pollution and certain other sources are required to apply for title 
V operating permits that include emissions limitations and other 
conditions as necessary to ensure compliance with the applicable 
requirements of the CAA, including the requirements of the applicable 
SIP. CAA sections 502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a). 
The ``applicable requirements'' that must be addressed in title V 
permits are defined in the title V regulations (40 CFR 70.2 and 71.2 
(definition of ``applicable requirement'')).
---------------------------------------------------------------------------

    \327\ Part 70 addresses requirements for state title V programs, 
and Part 71 governs the federal title V program.
---------------------------------------------------------------------------

    The EPA anticipates that, given the nature of the units subject to 
this proposed rule, most if not all of the sources at which the units 
are located are already subject to title V permitting requirements. For 
sources subject to title V, the interstate transport requirements for 
the 2015 ozone NAAQS that are applicable to them under the new or 
amended FIPs would be ``applicable requirements'' under title V and 
therefore must be addressed in the title V permits. For example, 
requirements concerning designated representatives, monitoring, 
reporting, and recordkeeping, the requirement to hold allowances 
covering emissions, the compliance assurance provisions, and liability 
are ``applicable requirements'' that must be addressed in the permits.
    Title V of the CAA establishes the basic requirements for state 
title V

[[Page 20152]]

permitting programs, including, among other things, provisions 
governing permit applications, permit content, and permit revisions 
that address applicable requirements under final FIPs in a manner that 
provides the flexibility necessary to implement market-based programs 
such as the trading programs established in CSAPR, the CSAPR Update, 
the Revised CSAPR Update and this proposed rule. 42 U.S.C. 7661a(b); 40 
CFR 70.6(a)(8) & (10); 40 CFR 71.6(a)(8) & (10).
    In CSAPR, the CSAPR Update and the Revised CSAPR Update, the EPA 
established standard requirements governing how sources covered by that 
rule would comply with title V and its regulations.\328\ 40 CFR 
97.506(d), 97.806(d) and 97.1006(d). For any new or existing sources 
subject to this proposed rule, identical title V compliance provisions 
would apply, just as they would have in the CSAPR NOX Ozone 
Season Group 3 Trading Program. For example, the title V regulations 
provide that a permit issued under title V must include ``[a] provision 
stating that no permit revision shall be required under any approved . 
. . emissions trading and other similar programs or processes for 
changes that are provided for in the permit.'' 40 CFR 70.6(a)(8) and 
71.6(a)(8). Consistent with these provisions in the title V 
regulations, in CSAPR, the CSAPR Update and the Revised CSAPR Update, 
the EPA included a provision stating that no permit revision is 
necessary for the allocation, holding, deduction, or transfer of 
allowances. 40 CFR 97.506(d)(1), 97.806(d)(1) and 97.1006(d)(1). This 
provision is also included in each title V permit for an affected 
source. This proposed rule maintains the approach taken under CSAPR, 
the CSAPR Update and the Revised CSAPR Update that allows allowances to 
be traded (or allocated, held, or deducted) without a revision to the 
title V permit of any of the sources involved.
---------------------------------------------------------------------------

    \328\ The EPA has also issued a guidance document and template 
that includes instructions for how to incorporate the applicable 
requirements into a source's Title V permit. See Memorandum dated 
May 13, 2015, from Anna Marie Wood, Director, Air Quality Policy 
Division, and Reid P. Harvey, Director, Clean Air Market Division, 
EPA, to Regional Air Division Directors, Subject: ``Title V Permit 
Guidance and Template for the Cross-State Air Pollution Rule'' 
(``2015 Title V Guidance''), available at https://www.epa.gov/sites/default/files/2016-10/documents/csapr_title_v_permit_guidance.pdf.
---------------------------------------------------------------------------

    Similarly, this proposed rule would also continue to support the 
means by which a source in the proposed trading program can use the 
title V minor modification procedure to change its approach for 
monitoring and reporting emissions, in certain circumstances. 
Specifically, sources may use the minor modification procedure so long 
as the new monitoring and reporting approach is one of the prior-
approved approaches under CSAPR, the CSAPR Update and the Revised CSAPR 
Update (i.e., approaches using a continuous emissions monitoring system 
under subparts B and H of part 75, an excepted monitoring system under 
appendices D and E to part 75, a low mass emissions excepted monitoring 
methodology under 40 CFR 75.19, or an alternative monitoring system 
under subpart E of part 75), and the permit already includes a 
description of the new monitoring and reporting approach to be used. 
See 40 CFR 97.506(d)(2), 97.806(d)(2) and 97.1006(d)(2); 40 CFR 
70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). As described in EPA's 
2015 Title V Guidance, sources may comply with this requirement by 
including a table of all of the approved monitoring and reporting 
approaches under CSAPR, the CSAPR Update and the Revised CSAPR Update 
trading programs in which the source is required to participate, and 
the applicable requirements governing each of those approaches.\329\ 
Inclusion of such a table in a source's title V permit therefore allows 
a covered unit that seeks to change or add to its chosen monitoring and 
recordkeeping approach to easily comply with the regulations governing 
the use of the title V minor modification procedure.
---------------------------------------------------------------------------

    \329\ Id.
---------------------------------------------------------------------------

    Under CSAPR, the CSAPR Update and the Revised CSAPR Update, in 
order to employ a monitoring or reporting approach different from the 
prior-approved approaches discussed previously, unit owners and 
operators must submit monitoring system certification applications to 
the EPA establishing the monitoring and reporting approach actually to 
be used by the unit, or, if the owners and operators choose to employ 
an alternative monitoring system, to submit petitions for that 
alternative to the EPA. These applications and petitions are subject to 
the EPA review and approval to ensure consistency in monitoring and 
reporting among all trading program participants. EPA's responses to 
any petitions for alternative monitoring systems or for alternatives to 
specific monitoring or reporting requirements are posted on EPA's 
website.\330\ The EPA maintains the same approach in this proposed 
rule.
---------------------------------------------------------------------------

    \330\ https://www.epa.gov/airmarkets/part-75-petition-responses.
---------------------------------------------------------------------------

    Consistent with EPA's approach under CSAPR, the CSAPR Update and 
the Revised CSAPR Update, the applicable requirements resulting from 
the new and amended FIPs generally will have to be incorporated into 
affected sources' existing title V permits either pursuant to the 
provisions for reopening for cause (40 CFR 70.7(f) and 71.7(f)) or the 
standard permit renewal provisions (40 CFR 70.7(c) and 71.7(c)).\331\ 
For sources newly subject to title V that are affected sources under 
the FIPs, the initial title V permit issued pursuant to 40 CFR 70.7(a) 
should address the final FIP requirements.
---------------------------------------------------------------------------

    \331\ A permit is reopened for cause if any new applicable 
requirements (such as those under a FIP) become applicable to an 
affected source with a remaining permit term of 3 or more years. If 
the remaining permit term is less than 3 years, such new applicable 
requirements will be added to the permit during permit renewal. See 
40 CFR 70.7(f)(1)(I) and 71.7(f)(1)(I).
---------------------------------------------------------------------------

    As was the case in the CSAPR, the CSAPR Update and the Revised 
CSAPR Update, the new and amended FIPs impose no independent permitting 
requirements and the title V permitting process will impose no 
additional burden on sources already required to be permitted under 
title V.

F. Relationship to Other Emissions Trading and Ozone Transport Programs

1. NOX SIP Call
    States affected by both the NOX SIP Call for the 1979 
ozone NAAQS and any final ozone season requirements established upon 
finalization of this proposed rule for the 2015 ozone NAAQS will be 
required to comply with the requirements of both rules. EPA is 
proposing to require NOX ozone season emissions reductions 
from EGUs larger than 25 MWe in many of the NOX SIP Call 
states, and at greater stringency than required by the NOX 
SIP Call, by requiring the EGUs to participate in the CSAPR 
NOX Ozone Season Group 3 Trading Program. Therefore, this 
proposed rule, if finalized, would satisfy the requirements of the 
NOX SIP Call for these large EGUs.
    In the Revised CSAPR Update, the EPA finalized the option for any 
NOX SIP Call state that was also subject to the Revised 
CSAPR Update to voluntarily submit a SIP revision to expand the 
applicability of the Group 3 trading program to include all 
NOX Budget Trading Program units, which in addition to large 
EGUs also include large non-EGU boilers and combustion turbines with a 
maximum design heat input greater than 250 mmBtu/hr. As part of such a 
SIP revision, the state

[[Page 20153]]

would be allowed to issue additional emissions allowances capped at a 
level intended to preserve the stringency of the Group 3 trading 
program. In today's proposed rule, the EPA is not proposing any changes 
to this provision of the Group 3 trading program.\332\
---------------------------------------------------------------------------

    \332\ In the CSAPR Update, the EPA finalized an identical option 
allowing NOX SIP Call states to expand applicability of 
the Group 2 trading program to cover certain non-EGUs. If the 
geographic expansion of the Group 3 trading program proposed in this 
rulemaking is finalized as proposed, no NOX SIP Call 
states would continue to be covered by the Group 2 trading program. 
Because the provision allowing NOX SIP Call states to 
expand applicability of the Group 2 trading program to include such 
non-EGUs would therefore be obsolete, the EPA is proposing to remove 
the provision.
---------------------------------------------------------------------------

2. Acid Rain Program
    This proposed rule, if finalized, would not affect any Acid Rain 
Program requirements. Any Title IV sources that are subject to 
provisions of this proposed rule would still need to continue to comply 
with all Acid Rain provisions. Acid Rain Program SO2 and 
NOX requirements are established independently in Title IV 
of the CAA and will continue to apply independently of this proposed 
rule's provisions. Acid Rain sources will still be required to comply 
with Title IV requirements, including the requirement to hold Title IV 
allowances to cover SO2 emissions after the end of a 
compliance year.
3. Other Current Emissions Trading Programs
    This proposed rule, if finalized, would not substantively affect 
any provisions of the CSAPR NOX Annual, CSAPR SO2 
Group 1, CSAPR SO2 Group 2, CSAPR NOX Ozone 
Season Group 1, or CSAPR NOX Ozone Season Group 2 trading 
programs for sources that continue to participate in those programs 
except with regard to the schedule for EPA to record certain allowance 
allocations, as discussed in Section VII.B.12 of this proposed rule. In 
addition, certain revisions are proposed to the CSAPR NOX 
Ozone Season Group 2 Trading Program regulations to address the 
proposed transition of sources in eight states from that program to the 
CSAPR NOX Ozone Season Group 3 Trading Program, as discussed 
in Section VII.B.11 of this proposed rule. Sources that are subject to 
any of the CSAPR trading programs will still be required to comply with 
all requirements, including the requirement to hold allowances to cover 
emissions after the end of a control period.

VIII. Environmental Justice Analytical Considerations and Stakeholder 
Outreach and Engagement

    Consistent with EPA's commitment to integrating environmental 
justice in the agency's actions, and following the directives set forth 
in multiple Executive Orders, the Agency has analyzed the impacts of 
this proposed rule on communities with environmental justice concerns 
and engaged with stakeholders representing these communities to seek 
input and feedback. Executive Order 12898 is discussed in Section XI.J 
of this proposed rule and analytical results are available in Chapter 7 
of the RIA.

A. Introduction

    Executive Order 12898 directs EPA staff to identify the populations 
of concern who are most likely to experience unequal burdens from 
environmental harms; specifically, minority populations, low-income 
populations, and indigenous peoples.\333\ Additionally, Executive Order 
13985 is intended to advance racial equity and support underserved 
communities through federal government actions.\334\ The EPA defines 
environmental justice as the fair treatment and meaningful involvement 
of all people regardless of race, color, national origin, or income, 
with respect to the development, implementation, and enforcement of 
environmental laws, regulations, and policies. EPA further defines the 
term fair treatment to mean that ``no group of people should bear a 
disproportionate burden of environmental harms and risks, including 
those resulting from the negative environmental consequences of 
industrial, governmental, and commercial operations or programs and 
policies.'' \335\ In recognizing that minority and low-income 
populations often bear an unequal burden of environmental harms and 
risks, EPA continues to consider ways of protecting them from adverse 
public health and environmental effects of air pollution.
---------------------------------------------------------------------------

    \333\ 59 FR 7629, February 16, 1994.
    \334\ 86 FR 7009, January 20, 2021.
    \335\ https://www.epa.gov/environmentaljustice.
---------------------------------------------------------------------------

B. Analytical Considerations

    EPA's environmental justice technical guidance \336\ states that 
``[t]he analysis of potential EJ concerns for regulatory actions should 
address three questions:
---------------------------------------------------------------------------

    \336\ U.S. Environmental Protection Agency (EPA), 2015. Guidance 
on Considering Environmental Justice During the Development of 
Regulatory Actions.

    1. Are there potential environmental justice concerns associated 
with environmental stressors affected by the regulatory action for 
population groups of concern in the baseline?
    2. Are there potential environmental justice concerns associated 
with environmental stressors affected by the regulatory action for 
population groups of concern for the regulatory option(s) under 
consideration?
    3. For the regulatory option(s) under consideration, are 
potential environmental justice concerns created or mitigated 
compared to the baseline?''

    To address these questions in EPA's first quantitative EJ analysis 
in the context of a transport rule, the EPA developed a unique 
analytical approach that considers the purpose and specifics of the 
proposed rulemaking, as well as the nature of known and potential 
exposures and impacts. However, due to data limitations, it is possible 
that our analysis failed to identify disparities that may exist, such 
as potential environmental justice characteristics (e.g., unemployed), 
environmental impacts (e.g., other ozone metrics), and more granular 
spatial resolutions (e.g., neighborhood scale) that were not evaluated.
    For the proposed rule, we employ two types of analytics to respond 
to the above three questions: Proximity analyses and exposure analyses. 
Both types of analyses can inform whether there are potential EJ 
concerns for population groups of concern in the baseline (question 
1).\337\ In contrast, only the exposure analyses, which are based on 
future air quality modeling, can inform whether there will be potential 
EJ concerns after implementation of the regulatory options under 
consideration (question 2) and whether potential EJ concerns will be 
created or mitigated compared to the baseline (question 3). While the 
exposure analysis can respond to all three questions, it should be 
noted that exposure is limited to a single ozone metric, the maximum 
daily 8-hour average, averaged across the April through September warm 
season (AS-MO3). This ozone metric likely smooths potential daily ozone 
gradients and is not directly relatable to the National Ambient Air 
Quality Standard (NAAQS). Additionally, the ozone exposure analytic 
results are provided in two formats: Aggregated and distributional. The 
aggregated results provide an overview of potential ozone exposure 
differences across populations at the national- and state-levels, while 
the distributional results show detailed

[[Page 20154]]

information about ozone concentrations experienced by everyone within 
each population.
---------------------------------------------------------------------------

    \337\ The baseline for proximity analyses is current population 
information (e.g., 2021), whereas the baseline for ozone exposure 
analyses are the future years in which the regulatory options will 
be implemented (e.g., 2023 and 2026).
---------------------------------------------------------------------------

    In Chapter 7 of the RIA we utilize the two types of analytics to 
address the three EJ questions by quantitatively evaluating (1) the 
proximity of affected facilities to potentially disadvantaged 
populations (Section 7.3.1), (2) the potential for disproportionate 
total ozone concentrations in the baseline across different demographic 
groups (Sections 7.4.1.1 and 7.4.2.1), and (3) how regulatory 
alternatives differentially impact the ozone concentration changes 
experienced by different demographic populations (Sections 7.4.1.2 and 
7.4.2.2). Each of these analyses depends on mutually exclusive 
assumptions, was performed to answer separate questions, and is 
associated with unique limitations and uncertainties.
    Baseline demographic proximity analyses can be relevant for 
identifying populations that may be exposed to local pollutants, such 
as NO2 emitted from affected sources in this proposed rule. 
However, such analyses are less useful here as they do not account for 
the potential impacts of this proposed rule on long-range ozone 
concentration changes. The baseline demographic proximity analysis 
presented in the RIA finds larger percentages of Hispanic individuals, 
Black individuals, people below the poverty level, people with less 
educational attainment, and people linguistically isolated living 
within 5 km and 10 km of an affected EGU, compared to national 
averages. It also finds larger percentages of people below the poverty 
level and with less educational attainment living within 5 km and 10 km 
of an affected non-EGU. Separately, the tribal proximity analysis finds 
multiple tribes and unique tribal lands located within 50 miles of an 
affected facility. These results do not in themselves demonstrate 
disproportionate impacts of affected facilities in the baseline but 
could suggest that emission reductions from this proposed rule may be 
responsive to potential local air quality concerns of nearby 
communities.
    Whereas the proximity analyses are limited to evaluating local 
pollutants under baseline scenarios (question 1), the ozone exposure 
analyses can provide insight into all three EJ questions with regard to 
AS-MO3 concentrations. Even though both the proximity and ozone 
exposure analyses can improve understanding of baseline EJ concerns 
(question 1), the two should not be directly compared. This is because 
the demographic proximity analysis does not include air quality 
information and is based on current, not future, population 
information.
    Importantly, the baseline analysis of AS-MO3 ozone concentrations 
responds to question 1 from EPA's environmental justice technical 
guidance document more directly than the proximity analyses, as it 
evaluates a form of the environmental stressor targeted by the 
regulatory action. Baseline AS-MO3 analyses show that certain 
populations, such as American Indians, Hispanics, and Asians, may 
experience somewhat higher AS-MO3 concentrations compared to the 
national average. The less educated and children may also experience 
higher concentrations compared to the national average, but to a lesser 
extent. Conversely, Black populations may experience lower AS-MO3 
concentrations than the national average. Therefore, also in response 
to question 1, there likely are potential environmental justice 
concerns associated with ozone exposures affected by the regulatory 
action for population groups of concern in the baseline. However, these 
baseline exposure results have not been fully explored and additional 
analyses are likely needed to understand potential implications.
    The ozone exposure analysis evaluates the impacts of the proposed 
rule on future ozone concentrations after rule implementation. When 
comparing across the policy, more-, and less-stringent regulatory 
alternatives, AS-MO3 concentrations are reduced across all populations 
evaluated in both future years and across both EGUs and non-EGUs. In 
other words, we expect that populations experiencing disproportionate 
AS-MO3 exposures in the baseline will experience similar 
disproportionate AS-MO3 exposures under the proposed rulemaking, 
although to a lesser absolute extent as the action described in this 
proposed rule is expected to lower ozone in many areas, including 
residual ozone nonattainment areas, and thus alleviate some pre-
existing health risks of ozone across all populations evaluated. 
Therefore, in response to question 2, we expect that there will be 
potential EJ concerns with regard to AS-MO3 concentrations after 
implementation of the regulatory options under consideration.
    Question 3 asks whether potential EJ concerns will be created or 
mitigated as compared to the baseline. As the RIA estimates 
disproportionate AS-MO3 exposures in the baseline and similar 
reductions in all population evaluated, we do not predict that 
potential EJ concerns related to AS-MO3 concentrations will be created 
or mitigated as compared to the baseline (question 3).
    The ozone exposure results should not be extrapolated to ozone 
metrics other than AS-MO3. Detailed environmental justice analytical 
results can be found in Chapter 7 of the RIA.

C. Outreach and Engagement

    Prior to this proposed rule, EPA initiated a public outreach effort 
to gather input from stakeholder groups likely to be interested in this 
proposed rule. Specifically, the EPA hosted an environmental justice 
webinar on October 26, 2021, to share information about the proposed 
rule and solicit feedback about potential environmental justice 
considerations. The webinar was attended by over 180 individuals 
representing state governments, federally recognized tribes, 
environmental NGOs, higher education institutions, industry, and the 
EPA.\338\ Participants were invited to comment during the webinar or 
provide written comments to a pre-regulatory docket. The webinar was 
recorded and distributed to attendees after the event. Some of the key 
issues raised by stakeholders during the webinar and in the pre-
proposal comments are described below.
---------------------------------------------------------------------------

    \338\ This does not constitute EPA's tribal consultation under 
E.O. 13175, which is described in Section XI.F of this proposed 
rule.
---------------------------------------------------------------------------

    Daily emissions rate limits. Several commenters asserted that cap 
and trade programs with seasonal limits on overall NOX 
emissions do not prevent facilities from running their controls 
inefficiently on high ozone days. These commenters recommended that 
facilities linked to downwind ozone problems comply with daily rate 
limits to ensure that emissions reductions occur on days when ozone is 
highest. The commenters noted that daily limits could particularly 
benefit environmental justice communities located near facilities and 
would also benefit those located downwind.
    Regulation of other sources. Several commenters asserted that the 
EPA should consider regulation of sources other than EGUs and sources 
of NOX in rulemakings pertaining to issues of ozone 
transport. For example, some commenters asserted that the EPA should 
regulate emissions from non-EGUs, mobile sources, and sources of VOCs.
    Environmental justice analysis and methodology in rulemakings. 
Several commenters offered recommendations to improve environmental 
justice analysis and methodology in rulemakings that address air 
pollution.

[[Page 20155]]

One commenter recommended that the EPA should broadly: (1) Identify 
communities of interest, based on the number of and proximity to 
polluting facilities; (2) integrate demographic factors to discern 
social, economic, and racial disparities in these areas; (3) consider 
the community's particular vulnerabilities and sensitivities to health 
harms and risks, and exposure to cumulative health harms and risks; and 
(4) reach out to the community members near such facilities themselves 
to gain tangible, lived experiences across their lifetimes. The 
commenter also suggested that the EPA should build off factors 
identified in existing environmental justice screening tools, including 
EPA EJSCREEN and California's CalEnviroScreen. One commenter noted that 
in developing environmental justice analyses, the EPA should consider 
and address the need for regulatory certainty, including the need for 
clear regulatory definitions of environmental justice areas and clear 
requirements for those areas.
    Environmental justice stakeholder outreach in rulemakings. Some 
commenters asserted that the EPA could improve stakeholder outreach in 
the rulemaking process. For example, one commenter noted that during 
the development of a rule proposal, the EPA could more directly reach 
out to all potentially impacted environmental justice communities, be 
more prepared to answer questions about the rule proposal, and be more 
aware of holidays when establishing comment periods.
    Additionally, some comments touched on issues that are also 
relevant to other EPA policies and programs. For example, some 
commenters asserted that the EPA should base air pollutant transport 
policy more on monitored data rather than modeling data to promptly 
address air pollution in areas where current monitoring data indicates 
an exceedance of the NAAQS. Other commenters recommended that the EPA 
consider strengthening cost thresholds for Reasonably Available Control 
Technology (RACT), a program that is applicable to certain existing 
sources in non-attainment areas.
    In addition to the engagement conducted prior to this proposed 
rule, EPA is providing the public, including those communities 
disproportionately impacted by the burdens of pollution, opportunities 
to engage in the EPA's public comment period for this proposed rule, 
including by hosting a public hearing. This public hearing will occur 
according to the schedule identified in the Public Participation 
section of this proposed rule.

IX. Costs, Benefits, and Other Impacts of the Proposed Rule

    In the Regulatory Impact Analysis for the proposed Federal 
Implementation Plan Addressing Regional Ozone Transport for the 2015 
Ozone National Ambient Air Quality Standards (RIA), EPA estimated the 
benefits, compliance costs, and emissions changes that may result from 
the proposed rule for the analysis period 2023 to 2042. The estimated 
benefits and compliance costs are presented in detail in the RIA 
accompanying this proposed rule. EPA notes that for EGUs the estimated 
benefits and compliance costs are directly associated with generation 
shifting to minimize costs; fully operating existing SCRs during ozone 
season; fully operating existing SNCRs during ozone season; installing 
state-of-the-art combustion controls; imposing backstop emission rate 
limits on certain units that lack SCR controls; and unit-level 
decisions to retrofit or retire. EPA also notes that for non-EGUs the 
estimated benefits and compliance costs are directly associated with 
installing controls to meet the NOX emissions limits 
presented in Section I.B above.
    For EGUs, EPA analyzed this proposed rule's emission budgets using 
uniform control stringency represented by $1,800 per ton of 
NOX (2016$) in 2023 and $11,000 per ton of NOX 
(2016$) in 2026. EPA also analyzed a more and a less stringent 
alternative. The more and less stringent alternatives differ from the 
proposed rule in that they set different NOX ozone season 
emission budgets for the affected EGUs and different dates for 
compliance with backstop emission rate limits.
    For non-EGUs, EPA analyzed this proposed rule using a marginal cost 
threshold of up to $7,500 per ton (2016$) for 2026 for the following 
emissions units and industries: Reciprocating internal combustion 
engines in Pipeline Transportation of Natural Gas; kilns in Cement and 
Cement Product Manufacturing; boilers and furnaces in Iron and Steel 
Mills and Ferroalloy Manufacturing; furnaces in Glass and Glass Product 
Manufacturing; and high-emitting boilers in Basic Chemical 
Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp, 
Paper, and Paperboard Mills. The less stringent alternative assumes 
there are emissions limits for all emission units from the proposal 
except for high-emitting boilers in Basic Chemical Manufacturing, 
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and 
Paperboard Mills. The more stringent alternative assumes emissions 
limits for all emission units from the proposed rule and all boilers, 
not just high-emitting boilers, in Basic Chemical Manufacturing, 
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and 
Paperboard Mills.
    Table IX-1 provides the projected 2023 through 2027, 2030, 2035, 
and 2042 EGU emission reductions for the evaluated regulatory control 
alternatives. For additional information on emissions changes, see 
Table 4.6 and Table 4-7 in Chapter 4 of the RIA.

 Table IX-1--EGU Ozone Season NOX Emissions Changes and Annual Emissions Reductions (Tons) for NOX, SO2, PM2.5,
                         and CO2 for the Regulatory Control Alternatives From 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                                 Less stringent   More stringent
                                                                Proposed rule     alternative      alternative
----------------------------------------------------------------------------------------------------------------
2023:
    NOX (ozone season).......................................            6,000            6,000            7,000
    NOX (annual).............................................           10,000           10,000           10,000
    SO2 (annual) *...........................................  ...............            1,000            2,000
    CO2 (annual, thousand metric)............................  ...............  ...............  ...............
    PM2.5 (annual)...........................................  ...............  ...............  ...............
2024:
    NOX (ozone season).......................................           26,000           14,000           29,000
    NOX (annual).............................................           42,000           22,000           45,000
    SO2 (annual).............................................           42,000           20,000           43,000
    CO2 (annual, thousand metric)............................           18,000           10,000           19,000
    PM2.5 (annual)...........................................            4,000            1,000            4,000
2025:

[[Page 20156]]

 
    NOX (ozone season).......................................           46,000           22,000           51,000
    NOX (annual).............................................           73,000           33,000           80,000
    SO2 (annual).............................................           83,000           39,000           84,000
    CO2 (annual, thousand metric)............................           37,000           19,000           38,000
    PM2.5 (annual)...........................................            9,000            2,000            9,000
2026:
    NOX (ozone season).......................................           47,000           32,000           53,000
    NOX (annual).............................................           81,000           55,000           87,000
    SO2 (annual).............................................          106,000           76,000          108,000
    CO2 (annual, thousand metric)............................           40,000           26,000           42,000
    PM2.5 (annual)...........................................            9,000            5,000            9,000
2027:
    NOX (ozone season).......................................           49,000           42,000           54,000
    NOX (annual).............................................           88,000           76,000           95,000
    SO2 (annual).............................................          129,000          113,000          131,000
    CO2 (annual, thousand metric)............................           43,000           34,000           46,000
    PM2.5 (annual)...........................................           10,000            7,000           10,000
2030:
    NOX (ozone season).......................................           52,000           52,000           57,000
    NOX (annual).............................................           96,000           98,000          100,000
    SO2 (annual).............................................          104,000          100,000          103,000
    CO2 (annual, thousand metric)............................           50,000           45,000           50,000
    PM2.5 (annual)...........................................            9,000            9,000            9,000
2035:
    NOX (ozone season).......................................           49,000           50,000           52,000
    NOX (annual).............................................           90,000           93,000           93,000
    SO2 (annual).............................................           96,000           93,000           98,000
    CO2 (annual, thousand metric)............................           38,000           36,000           38,000
    PM2.5 (annual)...........................................           11,000           12,000           10,000
2042:
    NOX (ozone season).......................................           47,000           47,000           48,000
    NOX (annual).............................................           70,000           75,000           71,000
    SO2 (annual).............................................           54,000           50,000           54,000
    CO2 (annual, thousand metric)............................           25,000           23,000           24,000
    PM2.5 (annual)...........................................            8,000            9,000            8,000
----------------------------------------------------------------------------------------------------------------
*SO2 emissions reductions under the proposed rule are 350 tons and rounded to zero. SO2 emissions reductions
  under the less stringent alternative are 507 tons and rounded to 1,000 tons. SO2 emissions reductions are
  1,699 tons under the more stringent alternative and rounded to 2,000 tons. Given the rounding, the difference
  between the reductions under the proposed rule and the less stringent alternative is approximately 160 tons.

    Table IX-2 below provides a summary of the ozone season emissions 
for non-EGUs for the 23 states subject to the proposed non-EGU 
emissions limits starting in 2026, along with the estimated ozone 
season reductions for 2026 for the proposed rule and the less and more 
stringent alternatives. The analysis in the RIA assumes that the 
estimated reductions in 2026 will be the same in later years.

 Table IX-2--Ozone Season (OS) NOX Emissions and Emissions Reductions (Tons) for Non-EGUs for the Proposed Rule
                                 and the Less and More Stringent Alternatives *
----------------------------------------------------------------------------------------------------------------
                                                                               Less stringent    More stringent
                                             2019 OS NOX     Proposed rule--   alternative--OS   alternative--OS
                  State                     emissions \a\        OS NOX        NOX reductions    NOX reductions
                                                               reductions
----------------------------------------------------------------------------------------------------------------
AR......................................             8,265             1,654               922             1,654
CA......................................            14,579             1,666             1,598             1,777
IL......................................            16,870             2,452             2,452             2,553
IN......................................            19,604             3,175             2,787             3,175
KY......................................            11,934             2,291             2,291             2,291
LA......................................            35,831             6,769             4,121             6,955
MD......................................             2,365                45                45                45
MI......................................            18,996             2,731             2,731             3,093
MN......................................            17,591               673               673               789
MO......................................             9,109             3,103             3,103             3,103
MS......................................            12,284             1,761             1,577             1,761
NJ......................................             2,025                 0                 0                29
NV......................................             2,418                 0                 0                 0
NY......................................             6,003               500               389               613
OH......................................            19,729             2,790             2,611             2,814
OK......................................            22,146             3,575             3,575             3,871

[[Page 20157]]

 
PA......................................            15,861             3,284             3,132             3,340
TX......................................            47,135             4,440             4,440             6,596
UT......................................             6,276               757               757               757
VA......................................             7,041             1,563             1,465             1,660
WI......................................             6,571             2,150               677             2,234
WV......................................             9,825               982               982               982
WY......................................            10,335               826               826               826
                                         -----------------------------------------------------------------------
    Totals..............................           322,793            47,186            41,153            50,918
----------------------------------------------------------------------------------------------------------------
* In the non-EGU screening assessment for 2026, EPA estimated emissions reduction potential from the non-EGU
  industries and emissions units. In the screening assessment, EPA used CoST to identify emissions units,
  emissions reductions, and associated compliance costs to evaluate the effects of potential non-EGU emissions
  control measures and technologies. CoST is designed to be used for illustrative control strategy analyses
  (e.g., NAAQS regulatory impact analyses) and not for unit-specific, detailed engineering analyses. The
  estimates from CoST identify proxies for (1) non-EGU emissions units that have emissions reduction potential,
  (2) potential controls for and emissions reductions from these emissions units, and (3) control costs from the
  potential controls on these emissions units. The control cost estimates do not include monitoring,
  recordkeeping, reporting, or testing costs. This screening assessment is not intended to be, nor take the
  place of, a unit-specific detailed engineering analysis that fully evaluates the feasibility of retrofits for
  the emissions units, potential controls, and related costs.
\a\ EPA determined that the 2019 inventory was appropriate because it provided a more accurate prediction of
  potential near-term emissions reductions. The analysis in the RIA assumes that the 2019 ozone season emissions
  will be the same in 2026 and later years.

    For EGUs, the EPA analyzed ozone season NOX emission 
reductions and the associated costs to the power sector using the 
Integrated Planning Model (IPM) and its underlying data and inputs. For 
non-EGUs, the EPA analyzed ozone season NOX emission 
reductions and the associated costs for 2026 in the Non-EGU Screening 
Assessment memorandum. Table IX-3 reflects the estimates of the changes 
in the cost of supplying electricity for the regulatory control 
alternatives for EGUs and estimates of complying with the emissions 
limits for non-EGUs. For EGUs, compliance costs are negative in 2023. 
While seemingly counterintuitive, estimating negative compliance costs 
in a single year is possible given IPM's objective function is to 
minimize the discounted net present value (NPV) of a stream of annual 
total cost of generation over a multi-decadal time period. As such the 
model may undertake a compliance pathway that pushes higher costs later 
into the forecast period, since future costs are discounted more 
heavily than near term costs. This can result in a policy scenario 
showing single year costs that are lower than the Baseline, but over 
the entire forecast horizon, the policy scenario shows higher costs. 
For a detailed description of these cost trends, please see Chapter 4, 
Section 4.5.2 of the RIA. For a detailed description of the methods and 
results from Non-EGU Screening Assessment memorandum, see Chapter 4, 
Sections 4.4 and 4.5.2 of the RIA.

                     Table IX-3--Total Estimated Compliance Costs (Million 2016$), 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                               Less-stringent    More-stringent
                                                              Proposed rule      alternative       alternative
----------------------------------------------------------------------------------------------------------------
2023:
    EGUs...................................................             -209              -173              -178
    Non-EGUs...............................................  ...............  ................  ................
    Total..................................................             -209              -173              -178
2026:
    EGUs...................................................              707              -406             1,180
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,117               -49             1,625
2027:
    EGUs...................................................            1,544             1,540             1,983
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,955             1,896             2,428
2030:
    EGUs...................................................            1,235             1,200             1,740
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,646             1,557             2,185
2035:
    EGUs...................................................            1,729             1,596             2,335
    Non-EGUs...............................................              411               357               445
    Total..................................................            2,139             1,953             2,780
2042:
    EGUs...................................................              910             1,757             1,001
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,321             2,114             1,446
----------------------------------------------------------------------------------------------------------------


[[Page 20158]]

    Tables IX-4 and IX-5 report the estimated economic value of avoided 
premature deaths and illness in each year relative to the baseline 
along with the 95% confidence interval. In each of these tables, for 
each discount rate and regulatory control alternative, multiple 
benefits estimates are presented reflecting alternative ozone and 
PM2.5 mortality risk estimates. For additional information 
on these benefits, see Chapter 5 of the RIA.

 Table IX-4--Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and
                                Illness for the Proposed Policy Scenarios in 2023
                              [95% Confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                       More stringent          Less stringent
      Disc. rate            Pollutant             Proposal               alternative            alternative
----------------------------------------------------------------------------------------------------------------
3%....................  Ozone Benefits...  $57 ($15 to $120) \c\   $65 ($17 to $140) \c\   $57 ($15 to $120) \c\
                                            and $460 ($51 to        and $530 ($59 to        and $460 ($51 to
                                            $1,200) \d\.            $1,400) \d\.            $1,200).\d\
                        PM Benefit Per     $44 and $45...........  $190 and $190.........  $59 and $60.
                         Ton (BPT)s.
                        Ozone Benefits     $100 ($59 to $160) \c\  $250 ($200 to $330)     $120 ($74 to $180)
                         plus PM BPTs.      and $500 ($96 to        \c\ and $720 ($250 to   \c\ and $520 ($110
                                            $1,200) \d\.            $1,600) \d\.            to $1,300).\d\
7%....................  Ozone Benefits...  $51 ($9.6 to 110) \c\   $58 ($11 to $130) \c\   $51 ($9.6 to $110)
                                            and $410 ($42 to        and $480 ($49 to        \c\ and $410 ($42 to
                                            $1,100) \d\.            $1,300) \d\.            $1,100).\d\
                        PM BPTs..........  $40 and $41...........  $170 and $170.........  $53 and $54.
                        Ozone Benefits     $90 ($49 to $150) \c\   $230 ($180 to $300)     $100 ($63 to $170)
                         plus PM BPTs.      and $450 ($83 to        \c\ and $650 ($220 to   \c\ and $470 ($97 to
                                            $1,100) \d\.            $1,400) \d\.            $1,100).\d\
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. The two benefits estimates are separated by the word ``and'' to
  signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates
  and should not be summed.
\b\ We estimated ozone benefits for changes in NOX for the ozone season and changes in PM2.5 and PM2.5
  precursors for EGUs in 2023. This table does not include benefits from reductions for non-EGUs because
  reductions from these sources are not expected prior to 2026 when the proposed standards would become
  effective.
\c\ Using the pooled short-term ozone exposure mortality risk estimate.
\d\ Using the long-term ozone exposure mortality risk estimate.


 Table IX-5--Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and
                                Illness for the Proposed Policy Scenario in 2026
                              [95% Confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                       More stringent          Less stringent
      Disc. rate            Pollutant             Proposal               alternative            alternative
----------------------------------------------------------------------------------------------------------------
3%....................  Ozone Benefits...  $1,200 ($310 to         $1,300 (340 to $2,900)  $830 ($210 to $1,800)
                                            $2,600) \c\ and         \c\ and $11,000         \c\ and $6,900 ($760
                                            $10,000 ($1,100 to      ($1,200 to $29,000)     to $18,000).\d\
                                            $26,000) \d\.           \d\.
                        PM BPTs..........  $8,100 and $8,300.....  $7,800 and $7,900.....  $3,400 and $3,500.
                        Ozone Benefits     $9,300 ($8,400 to       $9,100 ($8,100 to       $4,300 ($3,700 to
                         plus PM BPTs.      $11,000) \c\ and        $11,000) \c\ and        $5,200) \c\ and
                                            $18,000 ($9,400 to      $19,000 ($9,200 to      $10,000 ($4,300 to
                                            $35,000) \d\.           $37,000) \d\.           $22,000).\d\
7%....................  Ozone Benefits...  $1,100 ($200 to         $1,200 ($220 to         $740 ($140 to $1,700)
                                            $2,400) \c\ and         $2,700) \c\ and         \c\ and $6,200 ($630
                                            $9,000 ($920 to         $10,000 ($1,000 to      to $16,000).\d\
                                            $24,000) \d\.           $26,000) \d\.
                        PM BPTs..........  $7,300 and $7,400.....  $7,000 and $7,100.....  $3,100 and $3,200.
                        Ozone Benefits     $8,400 ($7,500 to       $8,200 ($7,200 to       $3,800 ($3,200 to
                         plus PM BPTs.      $9,700) \c\ and         $9,700) \c\ and         $4,800) \c\ and
                                            $16,000 ($8,300 to      $17,000 ($8,200 to      $9,300 ($3,800 to
                                            $31,000) \d\.           $34,000) \d\.           $19,000).\d\
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. The two benefits estimates are separated by the word ``and'' to
  signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates
  and should not be summed.
\b\ We estimated changes in NOX for the ozone season and changes in PM2.5 and PM2.5 precursors in 2026. This
  table represents changes in EGU and non-EGU ozone season and annual controls.
\c\ Sum of ozone mortality estimated using the pooled short-term ozone exposure risk estimate and the Di et al.
  (2017) long-term PM2.5 exposure mortality risk estimate.
\d\ Sum of the Turner et al. (2016) long-term ozone exposure risk estimate and the Di et al. (2017) long-term
  PM2.5 exposure mortality risk estimate.

    In Tables IX-6, IX-7, and IX-8, EPA presents a summary of the 
monetized benefits, costs, and net benefits of the proposal and the 
more and less stringent alternatives for 2023, 2026, and 2030, 
respectively. The monetized benefits estimates do not include important 
climate benefits that were not monetized in the RIA. In addition, there 
are important water quality benefits and health benefits associated 
with reductions in concentrations of air pollutants other than 
PM2.5 and ozone that are not quantified. We request comment 
on how to address the climate benefits and other categories of non-
monetized benefits of the proposed rule. Discussion of the non-
monetized health, climate, welfare, and water quality benefits is found 
in Chapter 5 of the RIA.

Table IX-6--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2023 for the U.S.
                                           [Millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $100 and $500..........  $120 and $520..........  $250 and $720.
Costs \d\............................  -$210..................  -$170..................  -$180.
Net Benefits.........................  $310 and $710..........  $290 and $690..........  $430 and $900.
Benefits \c\ (7%)....................  $90 and $450...........  $100 and $470..........  $230 and $650.
Costs \d\............................  -$210..................  -$170..................  -$180
Net Benefits.........................  $300 and $660..........  $280 and $640..........  $400 and $820.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2023, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.

[[Page 20159]]

 
\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for
  more discussion. In addition, there are important unquantified water quality benefits and benefits associated
  with reductions in other air pollutants.
\d\ The costs presented in this table are 2023 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.


Table IX-7--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2026 for the U.S.
                                           [Millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $9,300 and $18,000.....  $4,300 and $10,000.....  $9,100 and $19,000.
Costs \d\............................  $1,100.................  -$49...................  $1,600.
Net Benefits.........................  $8,200 and $17,000.....  $4,300 and $10,000.....  $7,500 and $17,000.
Benefits \c\ (7%)....................  $8,400 and $16,000.....  $3,800 and $9,300......  $8,200 and $17,000.
Costs \d\............................  $1,100.................  -$49...................  $1,600
Net Benefits.........................  $7,300 and $15,000.....  $9,300 and $3,900......  $6,600 and $15,000.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2026, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.
\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for
  more discussion. In addition, there are important unquantified water quality benefits and benefits associated
  with reductions in other air pollutants.
\d\ The costs presented in this table are 2026 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.


Table IX-8--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2030 for the U.S.
                                           (Millions of 2016$) \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $9,400 and $20,000.....  $4,300 and $11,000.....  $9,200 and $21,000.
Costs \d\............................  $1,600.................  $1,600.................  $2,200.
Net Benefits.........................  $7,700 and $18,000.....  $2,800 and $9,700......  $7,000 and $19,000.
Benefits \c\ (7%)....................  $8,400 and $18,000.....  $3,900 and $10,000.....  $8,300 and $19,000.
Costs \d\............................  $1,600.................  $1,600.................  $2,200.
Net Benefits.........................  $6,800 and $16,000.....  $2,300 and $8,400......  $6,100 and $16,000.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2030, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.
\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposed rule conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA
  for more discussion. In addition, there are important unquantified water quality benefits and benefits
  associated with reductions in other air pollutants.
\d\ The costs presented in this table are 2030 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.

    In addition, Table IX-9 presents estimates of the present value 
(PV) of the monetized benefits and costs and the equivalent annualized 
value (EAV), an estimate of the annualized value of the net benefits 
consistent with the present value, over the twenty-year period of 2023 
to 2042. The estimates of the PV and EAV are calculated using discount 
rates of 3 and 7 percent as directed by OMB's Circular A-4 and are 
presented in 2016 dollars discounted to 2022.

[[Page 20160]]



 Table IX-9--Monetized Estimated Benefits, Compliance Costs, and Net Benefits of the Proposed Rule and Less and
                                 More Stringent Alternatives, 2023 Through 2042
                                    (Millions 2016$, discounted to 2022) \a\
----------------------------------------------------------------------------------------------------------------
                                                      3 Percent discount rate         7 Percent discount rate
                                                 ---------------------------------------------------------------
                                                        PV              EAV             PV              EAV
----------------------------------------------------------------------------------------------------------------
                                                    Benefits
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................        $250,000         $17,000        $150,000         $14,000
Less Stringent Alternative......................         150,000           9,500          88,000           7,800
More Stringent Alternative......................         270,000          17,000         160,000          14,000
----------------------------------------------------------------------------------------------------------------
                                                Compliance Costs
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................          22,000           1,500          14,000           1,300
Less Stringent Alternative......................          20,000           1,300          12,000           1,100
More Stringent Alternative......................          28,000           1,900          18,000           1,700
----------------------------------------------------------------------------------------------------------------
                                                  Net Benefits
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................         220,000          15,000         130,000          12,000
Less Stringent Alternative......................         120,000           8,100          70,000           6,600
More Stringent Alternative......................         230,000          15,000         130,000          12,000
----------------------------------------------------------------------------------------------------------------
\a\ The U.S. District Court for the Western District of Louisiana has issued an injunction concerning the
  monetization of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana
  v. Biden, No. 21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the
  benefit-cost analysis of this proposed rule conducted pursuant to E.O. 12866.

    As shown in Table IX-9, the PV of the benefits of this proposed 
rule, discounted at a 3-percent discount rate, is estimated to be about 
$250,000 million, with an EAV of about $17,000 million. At a 7-percent 
discount rate, the PV of the benefits is estimated to be $150,000 
million, with an EAV of about $14,000 million. The PV of the compliance 
costs, discounted at a 3-percent rate, is estimated to be about $22,000 
million, with an EAV of about $1,500 million. At a 7-percent discount 
rate, the PV of the compliance costs is estimated to be about $14,000 
million, with an EAV of about $1,300 million.
    In addition to the analysis of costs and benefits, EPA also 
estimated the impacts on projected 2023 and 2026 ozone design values 
that are expected from the EGU and non-EGU control alternatives in this 
proposed rule. As described above, the alternative scenarios include 
the proposed rule along with scenarios that reflect less stringent and 
more stringent alternatives for EGUs and non-EGUs. The projected ozone 
design values and ozone impacts estimated in 2023 and 2026 for the 
proposed, less stringent, and more stringent alternatives are provided 
in Appendix 3B of the RIA. In summary, the differences in the amount of 
ozone reduction across the three alternatives at individual receptors 
in 2023 are consistent with the relative changes in NOX 
emissions in this year under the different scenarios. Overall, in 2023 
the estimated ozone reductions from all three of the alternatives are 
projected to be less than 0.1 ppb at most receptors. The exceptions are 
at certain receptors in Connecticut, Illinois, Texas, and Utah where 
impacts are between 0.1 and 0.2 ppb. In 2026, the largest impacts in 
the proposed rule are estimated at the two receptors in Texas (i.e., 
Brazoria County and Harris County), where the average reduction is 1.3 
ppb. Elsewhere in 2026, the average reductions for the proposed rule 
are on the order of 0.5 ppb at receptors in Connecticut, Illinois, and 
Wisconsin. The average reduction for the four receptors in Utah is 
approximately 0.3 ppb, while the average reduction at receptors in 
Colorado and California are approximately 0.2 ppb. Overall, the less 
stringent alternative provides approximately 0.1 to 0.3 ppb less ppb 
reduction (i.e., 30 to 40 percent less reduction), on average, compared 
to the proposed rule at receptors in the East and in Colorado and Utah. 
The more stringent alternative does not appear to provide any notable 
additional ozone reductions compared to the proposed rule in all 
receptor areas, except at receptors in Connecticut and Texas where the 
average reduction increases by 0.1 ppb and 0.2 ppb with the more 
stringent alternative, respectively.
    Examining the projected average and maximum design values in 2023 
at individual receptors for the proposed, less stringent, and more 
stringent alternatives indicates that three of the receptors included 
in this impact analysis are projected to change attainment status in 
2023 as a result of this proposed rule. Specifically, receptors in 
Clark County, Nevada, Butte County, California, and Riverside County 
Californian (Monitor ID: 060650008) are projected to switch from 
maintenance-only in the 2023 baseline to attainment and the receptor in 
Harris County, Texas is projected to switch from nonattainment to 
maintenance-only under any of the alternatives in 2023. In 2026, six of 
the receptors in this analysis are projected to change attainment 
status as a result of the emissions reductions in this proposed rule. 
Specifically, Calaveras County, California, Brazoria County, Texas, and 
in Kenosha County, Wisconsin (Monitor ID: 550590025) are projected to 
switch from maintenance-only to attainment in 2026 and a receptor in 
Riverside County, California (Monitor ID: 060650016) is projected to 
switch from nonattainment to maintenance under any of the alternatives. 
The receptor in Douglas County, Colorado and one of the receptors in 
Cook County, Illinois (Monitor ID: 170310076) are projected to switch 
from maintenance-only to attainment under the proposed and more 
stringent alternatives, but these receptors are projected to remain as 
maintenance-only in the less stringent alternative. The projected 
design values and additional information on the ozone impact analysis 
can be found in Appendix 3B of the proposed rule RIA.

X. Summary of Proposed Changes to the Regulatory Text for the Federal 
Implementation Plans and Trading Programs for EGUs

    This section describes the proposed amendments to the regulatory 
text that

[[Page 20161]]

would implement the proposed findings and remedy discussed elsewhere in 
this proposed rule with respect to EGUs. The primary CFR amendments 
would be revisions to the FIP provisions addressing states' good 
neighbor obligations related to ozone in 40 CFR part 52 as well as the 
revisions to the regulations for the CSAPR NOX Ozone Season 
Group 3 Trading Program in 40 CFR part 97, subpart GGGGG. In 
conjunction with the amendments to the Group 3 trading program, the 
monitoring, recordkeeping, and reporting regulations in 40 CFR part 75 
would be amended to reflect the addition of certain new reporting 
requirements associated with the amended trading program and the 
administrative appeal provisions in 40 CFR part 78 would be amended to 
identify certain additional types of appealable decisions of the EPA 
Administrator under the amended trading program. The proposed 
provisions to address the transition of the EGUs in certain states from 
the Group 2 trading program to the Group 3 trading program would be 
implemented in part through revisions to regulations noted above and in 
part through revisions to the regulations for the Group 2 trading 
program in 40 CFR part 97, subpart EEEEE.
    In addition to these primary amendments, certain revisions are 
proposed to the regulations for the other CSAPR trading programs in 40 
CFR part 97, subparts AAAAA through EEEEE, and the Texas SO2 
Trading Program in 40 CFR part 97, subpart FFFFF, for conformity with 
the proposed amended provisions of the Group 3 trading program, as 
discussed in Section VII.B.12 of this proposed rule. Documents have 
been included in the docket for this proposed rule showing all of the 
proposed revisions in redline-strikeout format.

A. Amendments to FIP Provisions in 40 CFR Part 52

    The CSAPR, CSAPR Update, and Revised CSAPR Update FIP requirements 
related to ozone season NOX emissions are set forth in 40 
CFR 52.38(b) as well as other sections of part 52 specific to each 
covered state. The existing text of Sec.  52.38(b)(1) identifies the 
trading program regulations in 40 CFR part 97, subparts BBBBB, EEEEE, 
and GGGGG as constituting the relevant FIP provisions relating to 
seasonal NOX emissions and transported ozone pollution. 
Because the EPA is proposing in this rulemaking to establish new or 
amended FIP requirements not only for the types of EGUs covered by the 
trading programs but also for other types of sources, a proposed 
amendment to Sec.  52.38(b)(1) would clarify that the trading programs 
constitute the FIP provisions only for the sources meeting the 
applicability requirements of the trading programs. A parallel 
clarification would be added to Sec. Sec.  52.38(a)(1) and 52.39(a) 
with respect to the CSAPR FIP requirements relating to annual 
NOX emissions, SO2 emissions, and transported 
fine particulate pollution.
    The states whose EGU sources are required to participate in the 
CSAPR NOX Ozone Season Group 1, Group 2, and Group 3 trading 
programs under the FIPs established in CSAPR, the CSAPR Update, and the 
Revised CSAPR Update, as well as the control periods for which those 
requirements apply, are identified in Sec.  52.38(b)(2). Proposed 
amendments to this paragraph would expand the applicability of the 
Group 3 trading program to sources in the thirteen additional states 
that the EPA is proposing to add to the Group 3 trading program 
starting with the 2023 control period and would end the applicability 
of the Group 2 trading program (with the exception of certain 
provisions) for sources in eight of the thirteen states after the 2022 
control period, as discussed in Section VII.B.2 of this proposed 
rule.\339\ The current subparagraphs within Sec.  52.38(b)(2) would 
also be renumbered to clarify the organization of the provisions and to 
facilitate cross-references from other regulatory provisions. Regarding 
the two states currently participating in the Group 2 trading program 
through approved SIP revisions that replaced the previous FIPs issued 
under the CSAPR Update (Alabama and Missouri), a provision indicating 
that EPA would no longer administer the state trading programs adopted 
under those SIP revisions after the 2022 control period would be added 
at Sec.  52.38(b)(16)(ii)(B).
---------------------------------------------------------------------------

    \339\ Both the current text of Sec.  52.38(b)(2) and the 
proposed amended text expressly encompass sources in Indian country 
within the respective states' borders.
---------------------------------------------------------------------------

    In the Revised CSAPR Update, the EPA established several options 
for states to revise their SIPs to modify or replace the FIPs 
applicable to their sources while continuing to use the Group 3 trading 
program as the mechanism for meeting the states' good neighbor 
obligations. Existing Sec.  52.38(b)(10), (11), and (12) establish 
options to replace allowance allocations for the 2022 control period, 
to adopt an abbreviated SIP revision for control periods in 2023 or 
later years, and to adopt a full SIP revision for control periods in 
2023 or later years, respectively. As discussed in Section VII.D of 
this proposed rule, the EPA is proposing to retain these SIP revision 
options and to make them available for all states that would be covered 
by the Group 3 trading program after the proposed geographic expansion. 
The option under Sec.  52.38(b)(10) to replace allowance allocations 
for a single control period would be amended to be available for the 
2024 control period, with attendant revisions to the years and dates 
shown in Sec.  52.38(b)(10) (multiple paragraphs) and (b)(17)(i) as 
well as the Group 3 trading program regulations, as discussed in 
Section X.B of this proposed rule. The options under Sec.  52.38(b)(11) 
and (12) to adopt abbreviated or full SIP revisions would be amended to 
be available starting with the 2025 control period, with attendant 
revisions to Sec.  52.38(b)(11)(iii), (b)(12)(iii), and 
(b)(17)(ii).\340\
---------------------------------------------------------------------------

    \340\ No state currently in the Group 3 trading program has 
submitted a SIP revision to make use of these options in control 
periods before the control periods in which the options could be 
used under the proposed amendments.
---------------------------------------------------------------------------

    The proposed changes with respect to set-asides, the treatment of 
units in Indian country, and recordation schedules discussed in Section 
VII.B.9 of this proposed rule, although implemented largely through 
proposed amendments to the Group 3 trading program regulations, would 
also be implemented in part through proposed amendments to Sec.  
52.38(b)(11) and (12). First, the text in Sec.  52.38(b)(11)(iii)(A) 
and (b)(12)(iii)(A) identifying the portion of each state trading 
budget for which a state could establish state-determined allowance 
allocations would be revised to exclude any allowances in a new unit 
set-aside, Indian country new unit set-aside, or Indian country 
existing unit set-aside. Second, the text in Sec.  52.38(b)(12)(vi) 
identifying provisions that states could not adopt into their SIPs 
(because the provisions concern regulation of sources in Indian country 
not subject to a state's CAA implementation planning authority) would 
be revised to include the provisions of the amended Group 3 trading 
program addressing allocation and recordation of allowances from all 
types of set-asides. Third, the text in Sec.  52.38(b)(12)(vii) 
authorizing the EPA to modify the previous approval of a SIP revision 
with regard to the assurance provisions ``if and when a covered unit is 
located in Indian country'' would be revised to account for the fact 
that at least one covered unit would already be located in Indian 
country not subject to a state's jurisdiction if the geographic 
expansion proposed in this rulemaking

[[Page 20162]]

is finalized. Finally, the text in Sec.  52.38(b)(11)(iii)(B) and 
(b)(12)(iii)(B) would be revised to amend the deadline for states to 
submit state-determined allowance allocations to the EPA from June 1 in 
the third year before the relevant control period to June 1 in the year 
before the relevant control period.
    The proposed transitional provisions discussed in Section VII.B.11 
of this proposed rule to convert certain 2017-2022 Group 2 allowances 
to Group 3 allowances and to recall certain 2023-2024 Group 2 
allowances, although promulgated as amendments to the Group 2 trading 
program regulations, would necessarily be implemented after the end of 
the 2022 control period. Proposed amendments clarifying that these 
provisions continue to apply to the relevant sources and holders of 
allowances notwithstanding the transition of certain states out of the 
Group 2 trading program after the 2022 control period would be added at 
Sec.  52.38(b)(14)(iii)(F) and (G). Cross-references clarifying that 
EPA's allocations of the converted Group 3 allowances would not be 
subject to modification through SIP revisions would also be added to 
the existing provisions at Sec.  52.38(b)(11)(iii)(D) and 
(b)(12)(iii)(D).
    The general FIP provisions applicable to all states covered by this 
proposed rule as set forth in Sec.  52.38(b)(2) would be replicated in 
the state-specific subparts of 40 CFR part 52 for each of the thirteen 
states that the EPA is proposing to add to the Group 3 trading 
program.\341\ In each such state-specific CFR subpart, provisions would 
be added indicating that sources in the state are required to 
participate in the CSAPR NOX Ozone Season Group 3 Trading 
Program with respect to emissions starting in 2023. Provisions would 
also be added repeating the substance of Sec.  52.38(b)(13)(i), which 
generally provides that the Administrator's full and unconditional 
approval of a full SIP revision correcting the same SIP deficiency that 
is the basis for a FIP promulgated in this rulemaking would cause the 
FIP to no longer apply to sources subject to the state's CAA 
implementation planning authority, and Sec.  52.38(b)(14)(ii), which 
generally provides the EPA with authority to complete recordation of 
EPA-determined allowance allocations for any control period for which 
EPA has already started such recordation notwithstanding the approval 
of a state's SIP revision establishing state-determined allowance 
allocations.
---------------------------------------------------------------------------

    \341\ See proposed Sec. Sec.  52.54(b) (Alabama), 52.184(a) 
(Arkansas), 52.440(d) (Delaware), 52.1240(d) (Minnesota), 52.1824(a) 
(Mississippi), 52.1326(b) (Missouri), 52.1492 (Nevada), 52.1930(a) 
(Oklahoma), 52.2240(e) (Tennessee), 52.2283(d) (Texas), 52.2356 
(Utah), 52.2587(e) (Wisconsin), and 52.2638(a) (Wyoming).
---------------------------------------------------------------------------

    For each of the eight states that the EPA is proposing to remove 
from the Group 2 trading program, the current provisions of the state-
specific CFR subparts indicating that sources in the state are required 
to participate in that trading program would be revised to end that 
requirement with respect to emissions after 2022, and a further 
provision would be added repeating the substance of Sec.  
52.38(b)(14)(iii), which identifies certain provisions that continue to 
apply to sources and allowances notwithstanding discontinuation of a 
trading program with respect to a particular state.\342\ In addition, 
for the six states that during their time in the Group 2 trading 
program have not exercised the option to adopt full SIP revisions to 
replace the FIPs issued under the CSAPR Update (all but Alabama and 
Missouri), obsolete provisions concerning the unexercised SIP revision 
option would be removed.
---------------------------------------------------------------------------

    \342\ See proposed Sec. Sec.  52.54(b) (Alabama), 52.184(a) 
(Arkansas), 52.1824(a) (Mississippi), 52.1326(b) (Missouri), 
52.1930(a) (Oklahoma), 52.2240(e) (Tennessee), 52.2283(d) (Texas), 
and 52.2587(e) (Wisconsin).
---------------------------------------------------------------------------

    No amendments with respect to FIP requirements for EGUs would be 
made to the state-specific CFR subparts for the twelve states whose 
sources currently participate in the Group 3 trading program \343\ 
except as needed to update cross-references or to implement the 
proposed changes related to the treatment of Indian country, as 
discussed in Section X.D of this proposed rule.
---------------------------------------------------------------------------

    \343\ See proposed Sec. Sec.  52.731(b) (Illinois), 52.789(b) 
(Indiana), 52.940(b) (Kentucky), 52.984(d) (Louisiana), 52.1084(b) 
(Maryland), 52.1186(e) (Michigan), 52.1584(e) (New Jersey), 
52.1684(b) (New York), 52.1882(b) (Ohio), 52.2040(b) (Pennsylvania), 
52.2440(b) (Virginia), and 52.2540(b) (West Virginia).
---------------------------------------------------------------------------

B. Amendments to Group 3 Trading Program and Related Regulations

    To implement the geographic expansion of the Group 3 trading 
program and the revised trading budgets that would be established under 
the new and amended FIPs proposed in this rulemaking, several sections 
of the Group 3 trading program regulations would be amended. Revisions 
identifying the applicable control periods, deadlines for certification 
of monitoring systems, and deadlines for commencement of quarterly 
reporting for sources not previously covered by the Group 3 trading 
program would be made at Sec. Sec.  97.1006(c)(3)(i), 97.1030(b)(1), 
and 97.1034(d)(2)(i), respectively. Revisions identifying the proposed 
new or revised budgets and new unit set-asides for the 2023 and 2024 
control periods for all covered states would be made at Sec.  
97.1010(a)(1) and (b)(1), respectively.
    Each of the proposed enhancements to the Group 3 trading program 
discussed in Section VII.B of this proposed rule would also be 
implemented primarily through revisions to the trading program 
regulations. The dynamic budget-setting process discussed in Section 
VII.B.4 of this proposed rule would be implemented at Sec.  
97.1010(a)(2) and (3), and the associated revised process for 
determining variability limits and assurance levels discussed in 
Section VII.B.5 of this proposed rule would be implemented at Sec.  
97.1010(e). The Group 3 allowance bank recalibration process discussed 
in Section VII.B.6 of this proposed rule would be implemented at Sec.  
97.1026(d). The backstop daily NOX emissions rate component 
of the primary emissions limitation discussed in Section VII.B.7 would 
be implemented at Sec. Sec.  97.1006(c)(1)(i) and 97.1024(b)(1) and 
(3), accompanied by the addition of a definition of ``backstop daily 
NOX emissions rate'' and modification of the definition of 
``CSAPR NOX Ozone Season Group 3 allowance'' in Sec.  
97.1002. The secondary emissions limitation for sources found 
responsible for exceedances of the assurance levels discussed in 
Section VII.B.8 of this proposed rule would be implemented at 
Sec. Sec.  97.1006(c)(1)(iii) and (iv) and (c)(3)(ii) and 97.1025(c), 
accompanied by the addition of a definition of ``CSAPR NOX 
Ozone Season Group 3 secondary emissions limitation'' in Sec.  97.1002.
    The proposed changes relating to set-asides, the treatment of 
Indian country, unit-level allowance allocations, and recordation 
schedules discussed in Section VII.B.9 of this proposed rule would be 
implemented through revisions to multiple sections of Sec. Sec.  
97.1010, 97.1011, 97.1012, and 97.1021, as well as limited revisions to 
97.1002 (definition of ``allocate or allocation'') and 97.1006(b)(2). 
In Sec.  97.1010, paragraphs (b), (c), and (d) would address the 
amounts for each control period of the new unit set-asides, Indian 
country new unit set-asides, and Indian country existing unit set-
asides, respectively. Paragraphs (c) and (d) would reflect the 
discontinuation of Indian country new unit set-asides after the 2022 
control period and the establishment of Indian

[[Page 20163]]

country existing unit set-asides starting with the 2023 control 
period.\344\
---------------------------------------------------------------------------

    \344\ The current Sec.  97.1011(c), which addresses the 
relationships of set-asides and variability limits to state trading 
budgets, would be relocated to Sec.  97.1011(f).
---------------------------------------------------------------------------

    The proposed revisions to Sec.  97.1011 would refocus the section 
exclusively on allocation to ``existing'' units from the portion of 
each state emissions budget not reserved in a new unit set-aside or 
Indian country new unit set-aside. In Sec.  97.1011(a), the provision 
currently in Sec.  97.1011(a)(1) requiring allocations to existing 
units to be made in the amounts provided in notices of data 
availability (NODAs) issued by the EPA would be split into two separate 
provisions, with paragraph (a)(1) applying to existing units in the 
state and areas of Indian country covered by the state's CAA 
implementation planning authority and paragraph (a)(2) applying to 
existing units in areas of Indian country not covered by the state's 
CAA implementation planning authority.\345\ This split would facilitate 
the submission and approval of SIP revisions by states interested in 
submitting state-determined allowance allocations for the units over 
which they exercise CAA implementation authority, while leaving 
allocations to any units outside their authority to be addressed either 
by the EPA or by the relevant tribe under an approved tribal 
implementation plan. The proposed dynamic process for determining 
default allocations to existing units of allowances from state trading 
budgets starting with the 2025 control period would be set forth in 
revised Sec.  97.1011(b), while the current provisions of Sec.  
97.1011(b), which concern timing and notice procedures for allocations 
to new units, would be relocated to Sec.  97.1012. The provisions 
addressing incorrectly allocated allowances at Sec.  97.1011(c) would 
be streamlined by relocating the portions applicable to new units to 
Sec.  97.1012(c). In addition, as discussed in Section VII.B.9.d of 
this proposed rule, Sec.  97.1011(c)(5) would be revised to provide 
that, starting with the 2024 control period, any incorrectly allocated 
allowances recovered after May 1 of the year following the control 
period would not be reallocated to other units in the state but instead 
would be transferred to a surrender account.
---------------------------------------------------------------------------

    \345\ An additional provision currently in Sec.  97.1011(a)(1), 
which clarifies that an allocation or lack of allocation to a unit 
in a NODA does not constitute a determination by the EPA that the 
unit is or is not a CSAPR NOX Ozone Season Group 3 unit, 
would be relocated to Sec.  97.1011(a)(3). The current Sec.  
97.1011(a)(2), which provides for certain existing units that cease 
operations to receive allocations for their first five control 
periods of non-operation and provides for the allowances for 
subsequent control periods to be allocated to the relevant state's 
new unit set-asides, is inconsistent with the proposed revisions to 
the set-asides and the default allowance allocation process, as 
discussed in Section VII.B.9 of this proposed rule, and would be 
removed as obsolete.
---------------------------------------------------------------------------

    The proposed revisions to Sec.  97.1012 would retain the section's 
current focus on allocations to ``new'' units, generally combining the 
current provisions at Sec.  97.1012 with the current provisions at 
Sec.  97.1011(b) and (c) that address new units. The text of multiple 
paragraphs in both Sec.  97.1012(a) and (b) would be revised as needed 
to reflect the change in treatment of Indian country discussed in 
Section VII.B.9.a of this proposed rule, under which the new unit set-
asides would be used to provide allowance allocations to new units both 
in non-Indian country and Indian country within the borders of the 
respective states for control periods starting in 2023.\346\ The timing 
and notice provisions in proposed Sec.  97.1012(a)(13) and (b)(13) are 
relocated from current Sec.  97.1011(b)(1) and (2). The text of Sec.  
97.1012(c), addressing incorrect allocations to new units, is largely 
relocated from Sec.  97.1011(c) (which addresses incorrect allocations 
to existing units) and reflects a parallel proposed revision addressing 
the disposition of recovered allowances, as discussed in Section 
VII.B.9.d of this proposed rule.
---------------------------------------------------------------------------

    \346\ Revisions are also proposed to the text of Sec.  
97.1012(a) and (b) for the control periods in 2021 and 2022 
consistent with the proposed revisions to the parallel provisions in 
the regulations for the other CSAPR trading programs, generally 
calling for allocations to units in areas of Indian country subject 
to a state's CAA implementation planning authority to be made from 
the new unit set-asides instead of from the Indian country new unit 
set-asides.
---------------------------------------------------------------------------

    The proposed amendments to Sec.  97.1021 would implement three 
distinct sets of changes discussed in Sections VII.B.9 and VII.D.1 of 
this proposed rule. First, revisions to Sec.  97.1021(b) through (e) 
would replace the previous schedule for recording Group 3 allowances 
for the 2023 and 2024 control periods established in the Revised CSAPR 
Update with an updated recordation schedule tailored to the expected 
timing for issuance of a final rule in this rulemaking. The updated 
schedule would also reflect elimination of the unused former option for 
states to provide state-determined allowance allocations for the 2022 
control period and the proposed establishment of a substantively 
equivalent new option for states to provide state-determined allowance 
allocations for the 2024 control period. Second, revisions to Sec.  
97.1021(f) would change the schedule for recording allocations to 
existing units for future control periods from July 1 of the year three 
years before the control period to July 1 of the year before the 
control period. Finally, revisions to Sec.  97.1021(g) through (j) 
would end recordation for Indian country new unit set-asides after 
allocations for the 2022 control period, begin recordation for Indian 
country existing unit set-asides starting with allocations for the 2023 
control period, and modify the text to eliminate references to state-
determined allocations of allowances from new unit set-asides.
    Implementation of the proposed revisions to the Group 3 trading 
program would also be accomplished in part through amendments to 
regulations in other CFR parts. In 40 CFR part 75, which contains 
detailed monitoring, recordkeeping, and reporting requirements 
applicable to sources covered by the Group 3 trading program, the 
additional recordkeeping and reporting requirements discussed in 
Section VII.B.10.b of this proposed rule would be implemented through 
the addition of Sec. Sec.  75.72(f) and 75.73(f)(1)(ix) and (x) and 
revisions to Sec.  75.75, and the procedures for calculating daily 
total heat input and daily total NOX emissions and for 
apportioning NOX mass emissions monitored at a common stack 
among the individual units using the common stack would be added at 
sections 5.3.3, 8.4(c), and 8.5.3 of appendix F to part 75. In 40 CFR 
part 78, which contains the administrative appeal procedures applicable 
to decisions of the EPA Administrator under the Group 3 trading 
program, Sec.  78.1(b)(19) would be amended to list additional 
decisions made as part of the trading program enhancements that would 
be appealable under those procedures.

C. Transitional Provisions

    As discussed in Section VII.D.11 of this proposed rule, the EPA is 
proposing several transitional provisions for sources entering the 
Group 3 trading program. The provisions discussed in Section VII.D.11.a 
of this proposed rule, concerning the prorating of state emissions 
budgets, assurance levels, and unit-level allocations for the 2023 
control period, would be implemented through the Group 3 trading 
program regulations. Specifically, the state emissions budgets for the 
2023 control period would be prorated according to procedures set out 
at Sec.  97.1010(a)(1)(ii). Variability limits for the 2023 control 
period, and the resulting assurance levels, would be computed under 
Sec.  97.1010(e) from the prorated state emissions budgets. Unit-level

[[Page 20164]]

allocations to existing units for the 2023 control period would be 
computed from the prorated state emissions budgets according to 
procedures substantively the same as the procedures codified in Sec.  
97.1011(b) for calculating default allocations to existing units for 
later control periods, as discussed in Section VII.B.9.b of this 
proposed rule, and would be announced in the notice of data 
availability issued under Sec.  97.1011(a)(1) and (2) for the 2023 and 
2024 control periods.
    The remaining transitional provisions would be implemented through 
the Group 2 trading program regulations. The creation of an additional 
Group 3 allowance bank for the 2023 control period through the 
conversion of banked 2017-2022 Group 2 allowances as discussed in 
Section VII.B.11.b of this document would be implemented at Sec.  
97.826(e).\347\ Related provisions addressing the use of Group 3 
allowances to satisfy after-arising compliance obligations under the 
Group 2 trading program or the Group 1 trading program would be 
implemented at Sec. Sec.  97.826(f)(2) and 97.526(e)(3), respectively, 
and related provisions addressing recordation of late-arising 
allocations of Group 1 allowances would be implemented at Sec.  
97.526(d)(2)(iii). The recall of Group 2 allowances previously issued 
for the 2023 and 2024 control periods as discussed in Section 
VII.B.11.c of this document would be implemented at Sec.  97.811(e).
---------------------------------------------------------------------------

    \347\ The current provisions at Sec.  97.826(e) would be 
relocated to Sec.  97.826(f)(1) and (3).
---------------------------------------------------------------------------

    Decisions of the Administrator related to the allowance bank 
creation provisions and the allowance recall provisions would be 
identified as appealable decisions under 40 CFR part 78 through 
revisions to Sec.  78.1(b)(17)(viii) and (ix).

D. Clarifications and Conforming Revisions

    As discussed in Section VII.B.12 of this proposed rule, the EPA is 
proposing to make revisions to the provisions regarding allowance 
allocations for units in Indian country in all the CSAPR trading 
programs so that instead of distinguishing among units based on whether 
they are or are not located in Indian country, the revised provisions 
would distinguish among units based on whether they are or are not 
covered by a state's CAA implementation planning authority. The 
proposed revisions would be implemented in multiple paragraphs of 
Sec. Sec.  97.411(b), 97.412, 97.511(b), 97.512, 97.611(b), 97.612, 
97.711(b), 97.712, 97.811(b), and 97.812. The associated revisions to 
states' options regarding SIP revisions to establish state-determined 
allowance allocations for units covered by their CAA implementation 
planning authority would be implemented in multiple paragraphs of 
Sec. Sec.  52.38(a) and (b) and 52.39 as well as the state-specific 
subparts of 40 CFR part 52.
    As also discussed in Section VII.B.12 of this proposed rule, the 
EPA is proposing to revise the recordation schedule for allowance 
allocations to existing units under all the CSAPR trading programs, as 
well as the Texas SO2 Trading Program, so that starting with 
the 2025 control period the allocation deadline would generally be July 
1 of the year before the control period instead of July 1 of the year 3 
years before the control period. The revisions would be implemented at 
Sec. Sec.  97.421(f)(2), 97.521(f)(2), 97.621(f)(2), 97.721(f)(2), 
97.821(f), and 97.921(b)(2).
    Certain other revisions to the regulatory text in the FIP and 
trading program regulations are proposed as non-substantive 
clarifications. First, in the Group 2 trading program regulations, the 
paragraphs in Sec.  97.810 setting forth the amounts of state emissions 
budgets, new unit set-asides, Indian country new unit set-asides, and 
variability limits for states that the EPA is proposing to transition 
out of the Group 2 trading program would be modified to indicate that 
the amounts are applicable under that program only for control periods 
through 2022.
    Second, as noted in Section VII.F.1 of this proposed rule, the 
existing option for states subject to the NOX SIP Call to 
expand applicability of the Group 2 trading program to include certain 
large non-EGU boilers and combustion turbines would become obsolete if 
this rule is finalized as proposed because no NOX SIP Call 
states would continue to be covered by the Group 2 trading program. The 
proposed elimination of the obsolete option would be implemented in 
part through revisions to Sec.  52.38(b)(8) (multiple paragraphs), 
(b)(9) (multiple paragraphs), (b)(13)(ii), (b)(14)(i)(F), and 
(b)(16)(i)(B), and in part through revisions to the Group 2 trading 
program regulations at Sec. Sec.  97.806(c)(2) and (3), 97.825, and 
97.802 (removal of the definitions of ``base CSAPR NOX Ozone 
Season Group 2 source'' and ``base CSAPR NOX Ozone Season 
Group 2 unit'' and modification of the definitions of ``assurance 
account'', ``common designated representative'', common designated 
representative's assurance level'', and ``common designated 
representative's share'').
    Third, to clarify the regulatory text, the EPA is proposing to 
remove the language in the Group 3 trading program regulations 
finalized in the Revised CSAPR Update relating to the ``supplemental 
allowances'' issued for the 2021 control period in current Sec. Sec.  
97.1002 (definition of ``common designated representative's assurance 
level''), 97.1006(c)(2)(iii), 97.1010(d), and 97.1011(a)(1). In place 
of the removed language, the EPA proposes to restate the amounts of the 
state emissions budgets for the 2021 control period in Sec.  
97.1010(a)(1)(i) so as to include the amounts of the supplemental 
allowances in the restated budget amounts. The revised language would 
be substantively equivalent to and simpler than the current language.
    Fourth, in 40 CFR part 75, the EPA proposes to remove obsolete text 
in Sec.  75.73(c) and (f) to clarify the context for other text that 
would be added to the section, as discussed in Section X.B.
    Finally, the EPA proposes to update cross-references throughout 40 
CFR parts 52 and 97 for consistency with the other amendments proposed 
in this rulemaking.

XI. Statutory and Executive Orders Reviews

    Additional information about these statutes and Executive Orders 
(``E.O.'') 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 proposed rule is an economically significant regulatory action 
that was submitted to the Office of Management and Budget (OMB) for 
review. This proposed rule is in response to a court-ordered legal 
mandate and proposes to implement EGU and novel non-EGU NOX 
ozone season emissions reductions as part of the overall strategy for 
addressing interstate transport of ozone pollution for the 2015 ozone 
NAAQS. 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 proposed rule. This analysis, 
which is contained in the ``Regulatory Impact Analysis for the Proposed 
Federal Implementation Plan Addressing Regional Ozone Transport for the 
2015 Ozone National Ambient Air Quality Standard'' [EPA-452/R-15-009], 
is available in the docket and is briefly summarized in Section IX of 
this proposed rule.

[[Page 20165]]

B. Paperwork Reduction Act (PRA)

1. Information Collection Request for Electric Generating Units
    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that the EPA prepared has been assigned EPA ICR number 2709.01. EPA has 
placed a copy of the ICR in the docket for this rule, and it is briefly 
summarized here.
    EPA is proposing an information collection request (ICR), related 
specifically to electric generating units (EGU), for the proposed 
Federal Implementation Plan Addressing Regional Ozone Transport for the 
2015 Primary Ozone National Ambient Air Quality Standard. The proposed 
rule would amend the Cross-State Air Pollution Rule (CSAPR) 
NOX Ozone Season Group 3 trading program addressing seasonal 
NOX emissions in various states. Under the proposed 
amendments, all EGU sources in the original twelve Group 3 states 
(Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New 
Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia) 
would remain. Additionally, EGU sources in eight states (Alabama, 
Arkansas, Mississippi, Missouri, Oklahoma, Tennessee, Texas, and 
Wisconsin) currently covered by the CSAPR NOX Ozone Season 
Group 2 Trading Program would transition from the Group 2 program to 
the revised Group 3 trading program beginning with the 2023 ozone 
season. Further, sources in five states not currently covered by any 
CSAPR NOX ozone season trading program would join the 
revised Group 3 trading program: Delaware, Minnesota, Nevada, Utah, and 
Wyoming. In total, EGU sources in 25 states would now be covered by the 
Group 3 program.
    There is an existing ICR (OMB Control Number 2060-0667), that 
includes information collection requirements placed on EGU sources for 
the six Cross-State Air Pollution Rule (CSAPR) trading programs 
addressing sulfur dioxide (SO2) emissions, annual nitrogen 
oxides (NOX) emissions, or seasonal NOX emissions 
in various sets of states, and the Texas SO2 trading program 
which is modeled after CSAPR. This ICR accounts for the additional 
respondent burden related to the amendments to the CSAPR NOX 
Ozone Group 3 trading program.
    The principal information collection requirements under the CSAPR 
and Texas trading programs relate to the monitoring and reporting of 
emissions and associated data in accordance with 40 CFR part 75. Other 
information collection requirements under the programs concern the 
submittal of information necessary to allocate and transfer emission 
allowances and the submittal of certificates of representation and 
other typically one-time registration forms.
    Affected sources under the CSAPR and Texas trading programs are 
generally stationary, fossil fuel-fired boilers and combustion turbines 
serving generators larger than 25 megawatts (MW) producing electricity 
for sale. Most of these affected sources are also subject to the Acid 
Rain Program (ARP). The information collection requirements under the 
CSAPR and Texas trading programs and the ARP substantially overlap and 
are fully integrated. The burden and costs of overlapping requirements 
are accounted for in the ARP ICR (OMB Control Number 2060-0258). Thus, 
this ICR accounts for information collection burden and costs under the 
CSAPR NOX Ozone Season Group 3 trading program that are 
incremental to the burden and costs already accounted for in both the 
ARP and CSAPR ICRs.
    For most sources already reporting data under the CSAPR 
NOX Ozone Season Group 3 or CSAPR NOX Ozone Group 
2 trading programs, there would be no incremental burden or cost, as 
reporting requirements will remain identical. Certain sources with a 
common stack configuration and/or those that are large, coal-fired 
EGUs, will be subject to additional emission reporting requirements 
under the proposed rule. These sources will need to make a one-time 
monitoring plan and Data Acquisition and Handling System (DAHS) update 
to meet the additional reporting requirements. Remaining for assessment 
of incremental cost and burden are only those sources in the five 
states not currently reporting data under a CSAPR NOX Ozone 
Season program. Sources in Minnesota are already reporting data for the 
CSAPR NOX Annual program with almost identical information 
collection requirements, requiring only a one-time monitoring plan and 
DAHS update. Most of the affected sources in Delaware, Nevada, Utah, 
and Wyoming are already reporting data as part of the Acid Rain 
Program, thus only requiring a monitoring plan and DAHS update as well. 
Four additional EGUs in Delaware already report data under SIP 
requirements adopted to meet the NOX SIP Call and would face 
identical information requirements under this proposed rule. For the 
units that already report to EPA under the Acid Rain Program or the 
NOX SIP Call, with the exception of any one-time costs to 
update monitoring plans and DAHS, all information collection costs and 
burden are already reflected in the previously approved ICRs for those 
other rules (OMB Control Nos. 2060-0258 and 2060-0445).
    In total, there are an estimated 16 units in Delaware, Nevada, 
Utah, and Wyoming that do not already report data to EPA according to 
40 CFR part 75 and that would need to implement one of the Part 75 
monitoring methodologies including certification of monitoring systems 
or implementation of the low mass emissions methodology. These units 
would also require monitoring plan and DAHS updates. Of these sixteen 
units, two units would be expected to adopt low mass emissions (LME) as 
the monitoring method, thirteen would be expected to adopt Appendix D 
monitoring methods, and one would be expected to adopt CEMS monitoring 
methods.
    Respondents/affected entities: Industry respondents are stationary, 
fossil fuel-fired boilers and combustion turbines serving electricity 
generators subject to the CSAPR and Texas trading programs, as well as 
non-source entities voluntarily participating in allowance trading 
activities. Potential state respondents are states that can elect to 
submit state-determined allowance allocations for sources located in 
their states.
    Respondent's obligation to respond: Industry respondents: Voluntary 
and mandatory (Sections 110(a) and 301(a) of the Clean Air Act).
    Estimated number of respondents: EPA estimates that there would be 
188 industry respondents.
    Frequency of response: On occasion, quarterly, and annually.
    Total estimated additional burden: 1,834 hours (per year). Burden 
is defined at 5 CFR 1320.03(b).
    Total estimated additional cost: $396,520 (per year); includes 
$210,571 annualized capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. You may also send your ICR-related comments 
to

[[Page 20166]]

OMB's Office of Information and Regulatory Affairs via email to 
[email protected], Attention: Desk Officer for the EPA. Since 
OMB is required to make a decision concerning the ICR between 30 and 60 
days after receipt, OMB must receive comments no later than May 6, 
2022. The EPA will respond to any ICR-related comments in the final 
rule.
2. Information Collection Request for Non-Electric Generating Units
    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that the EPA prepared has been assigned EPA ICR number 2705.01. The EPA 
has filed a copy of the non-EGU ICR in the docket for this rule, and it 
is briefly summarized here.
    ICR No. 2705.01 is a new request and it addresses the burden 
associated with new regulatory requirements under the proposed rule. 
Owners and operators of certain non-Electric Generating Unit (non-EGU) 
industry stationary sources will potentially modify or install new 
emission controls and associated monitoring systems to meet the 
nitrogen oxides (NOX) emission limits of this proposed rule. 
The burden in this ICR reflects the new monitoring, calibrating, 
recordkeeping, reporting and testing activities required by industry 
and the administrative review conducted by the states of the associated 
industry activities. This information is being collected to assure 
compliance with the proposed rule. In accordance with the Clean Air Act 
Amendments of 1990, any monitoring information to be submitted by 
sources is a matter of public record. Information received and 
identified by owners or operators as confidential business information 
(CBI) and approved as CBI by EPA, in accordance with Title 40, Chapter 
1, Part 2, Subpart B, shall be maintained appropriately (see 40 CFR 2; 
41 FR 36902, September 1, 1976; amended by 43 FR 39999, September 8, 
1978; 43 FR 42251, September 28, 1978; 44 FR 17674, March 23, 1979).
    Respondents/affected entities: The respondents/affected entities 
are the owners/operators of certain non-EGU industry sources in the 
following industry sectors: Furnaces in Glass and Glass Product 
Manufacturing; boilers and furnaces in Iron and Steel Mills and 
Ferroalloy Manufacturing; kilns in Cement and Cement Product 
Manufacturing; reciprocating internal combustion engines in Pipeline 
Transportation of Natural Gas; and high-emitting equipment and large 
boilers in Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mill.
    Respondent's obligation to respond: Voluntary and mandatory. 
(Sections 110(a) and 301(a) of the Clean Air Act). All data that is 
recorded or reported by respondents is required by the proposed rule, 
titled ``Federal Implementation Plan Addressing Regional Ozone 
Transport for the 2015 Primary Ozone National Ambient Air Quality 
Standard: Transport Obligations for non-Electric Generating Units''.
    Estimated number of respondents: 489.
    Frequency of response: The specific frequency for each information 
collection activity within the non-EGU ICR is shown at the end of the 
ICR document in the Tables 1-11. In general, the frequency varies 
across the monitoring, recordkeeping, and reporting activities. Some 
recordkeeping such as work plan preparation is a one-time activity 
whereas engine maintenance recordkeeping is conducted quarterly. 
Reporting frequency is on a quarterly and semi-annual basis.
    Total estimated burden: 51,654 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $11,450,000 (average per year); includes 
$5,467,000 annualized capital or operation & maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information from 
the EGU ICR and non-EGU ICR, the accuracy of the provided burden 
estimates and any suggested methods for minimizing respondent burden to 
the EPA using the docket identified at the beginning of this rule. You 
may also send your ICR-related comments to OMB's Office of Information 
and Regulatory Affairs via email to [email protected], 
Attention: Desk Officer for the EPA. Since OMB is required to make a 
decision concerning the ICR between 30 and 60 days after receipt, OMB 
must receive comments no later than May 6, 2022. The EPA will respond 
to any ICR-related comments in the final rule.

C. Regulatory Flexibility Act (RFA)

    The EPA certifies that this proposed action will not have a 
significant economic impact on a substantial number of small entities 
under the Regulatory Flexibility Act (RFA). The Regulatory Flexibility 
Act (5 U.S.C. 601 et seq.), as amended by the Small Business Regulatory 
Enforcement Fairness Act (Pub. L. 104-121), provides that whenever an 
agency is required to publish a general notice of proposed rulemaking, 
it must prepare and make available an initial regulatory flexibility 
analysis, unless it certifies that the proposed rule, if promulgated, 
will not have a significant economic impact on a substantial number of 
small entities (5 U.S.C. 605(b)). Small entities include small 
businesses, small organizations, and small governmental jurisdictions.
    In 2026, EPA identified 34 small entities affected by the proposed 
rule, and of these 6 small entities may experience costs of greater 
than 1 percent of revenues. Of the 6 small entities projected to have 
costs greater than 1 percent of revenues, two of them operate in cost-
of-service regions and would generally be able to pass any increased 
costs along to rate-payers. In EPA's modeling, most of the cost impacts 
for these small entities and their associated units are driven by lower 
electricity generation relative to the base case baseline. 
Specifically, four units reduce their generation by significant 
amounts, driving the bulk of the costs for all small entities. Finally, 
EPA's decision to exclude units smaller than 25 MW capacity from the 
proposed FIP, and exclusion of uncontrolled units smaller than 100 MW 
from backstop emission rate limits has already significantly reduced 
the burden on small entities by reducing the number of affected small 
entity-owned units. Further, in 2026 for non-EGUs, there are five small 
entities, and one small entity is estimated to have a cost-to-sales 
impact of 1.3 percent of their revenues.
    The EPA has determined that an insignificant number of small 
entities potentially affected by the proposed rule will have compliance 
costs greater than 1 percent of annual revenues during the compliance 
period. EPA has concluded that there will be no significant economic 
impact on a substantial number of small entities (No SISNOSE) for this 
proposed rule overall. Details of this analysis are presented in 
Chapter 6 of the RIA, which is in the public docket.

D. Unfunded Mandates Reform Act (UMRA)

    This proposed action does not contain an unfunded mandate of $100 
million or more as described in UMRA, 2 U.S.C. 1531-1538, and will not 
significantly or uniquely affect small governments. Note

[[Page 20167]]

that we expect the proposed rule to potentially have an impact on only 
one category of government-owned entities (municipality-owned 
entities). This analysis does not examine potential indirect economic 
impacts associated with the proposed rule, such as employment effects 
in industries providing fuel and pollution control equipment, or the 
potential effects of electricity price increases on government 
entities. For more information on the estimated impact on government 
entities, refer to the RIA, which is in the public docket.

E. Executive Order 13132: Federalism

    This proposed action does not have federalism implications. If 
finalized, this proposed 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.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This proposed action has tribal implications. However, it would 
neither impose substantial direct compliance costs on federally 
recognized tribal governments, nor preempt tribal law.
    The EPA proposes to make a finding that interstate transport of 
ozone precursor emissions from 26 upwind states (Alabama, Arkansas, 
California, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New 
York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, 
West Virginia, Wisconsin, and Wyoming) is significantly contributing to 
downwind nonattainment or interfering with maintenance of the 2015 
ozone NAAQS in other states, based on projected nitrogen oxides 
(NOX) emissions in the 2023 ozone season. EPA is proposing 
to issue FIP requirements to eliminate interstate transport of ozone 
precursors from these 26 states that significantly contributes to 
nonattainment or interferes with maintenance of the NAAQS in other 
states. Under CAA section 301(d)(4), EPA proposes to extend FIP 
requirements to apply in Indian country located within the upwind 
geography of the proposed rule, including Indian reservation lands and 
other areas of Indian country over which EPA or a tribe has 
demonstrated that a tribe has jurisdiction. EPA's proposed extension is 
described further above in Section IV.C.2., Application of Rule in 
Indian Country and Necessary or Appropriate Finding. EPA proposes that 
all existing and new EGU and non-EGU sources that are located in the 
301(d) FIP areas within the geographic boundaries of the covered 
states, and which would be subject to this rule if located within areas 
subject to state CAA planning authority, should be included in this 
rule. This proposed action has tribal implication because of the 
proposed extension of FIP requirements into Indian country and this 
proposed rule may have additional tribal implications if a new affected 
EGU or non-EGU is built in Indian country. To EPA's knowledge, only one 
existing EGU or non-EGU source is located within the 301(d) FIP areas: 
The Bonanza Power Plant, an EGU source, located on the Uintah and Ouray 
Reservation, geographically located within the borders of Utah. In 
general, tribes have a vested interest in how this proposed rule would 
affect air quality.
    In the Revised CSAPR Update, EPA established default procedures for 
allocating CSAPR NOX Ozone Season Group 3 allowances 
(``Group 3 allowances'') in amounts equal to each state emissions 
budget for each control period among the sources in the state for use 
in complying with the Group 3 trading program. Under the current Group 
3 trading programs, reserved allowances are made available generally 
(but not exclusively \348\) to ``new'' units--which for purposes of the 
Revised CSAPR Update means units commencing commercial operation on or 
after January 1, 2019--through a ``new unit set-aside'' established for 
qualifying units in each state and, if areas of Indian country exist 
within the state's borders, a separate ``Indian country new unit set-
aside'' for qualifying units in such Indian country. In this 
rulemaking, EPA is proposing revisions to each step of the three-step 
allocation process to better address units in Indian country and to 
better coordinate the unit-level allocation process with the proposed 
dynamic budget-setting process.
    The EPA hosted an environmental justice webinar on October 26, 
2021, that was attended by state regulatory authorities, environmental 
groups, federally recognized tribes, and small business stakeholders. 
The EPA will also continue to consult with the government of the Ute 
Indian Tribe of the Uintah and Ouray Reservation and plans to further 
consult with any other tribal officials under the EPA Policy on 
Consultation and Coordination with Indian Tribes early in the process 
of developing this proposed regulation to solicit meaningful and timely 
input into its development. The EPA plans to issue tribal consultation 
letters addressed to 574 tribes in February 2022 after the proposed 
rule is signed. The EPA will likely facilitate an additional tribal 
consultation through a webinar before finalizing this proposed rule.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks 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 implements a previously promulgated 
health-based federal standard. This action's health and risk 
assessments are contained in Chapter 5 of this RIA. The EPA believes 
that the ozone-related benefits, PM2.5-related benefits, and 
CO2-related benefits from this proposed rule will further 
improve children's health. Additionally, the ozone exposure analysis in 
Chapter 7 of the RIA suggests that nationally, children (ages 0-17) 
will experience at least as great a reduction in ozone exposures as 
adults (ages 18-64) in 2023 and 2026 under all regulatory alternatives 
of this proposed rulemaking.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. EPA has prepared a Statement of Energy 
Effects for the proposed regulatory control alternative as follows. The 
Agency estimates a 1 percent change in retail electricity prices on 
average across the contiguous U.S. in 2025, a 7.8 percent reduction in 
coal-fired electricity generation, a 0.15 percent increase in natural 
gas-fired electricity generation, and a 3.8 percent increase in 
renewable electricity generation in 2025 as a result of this proposed 
rule. EPA projects that utility power sector delivered natural gas 
prices will change by less than 1 percent in 2025. Details of the 
estimated energy effects are presented in Chapter 4 of the RIA, which 
is in the public docket.

I. National Technology Transfer and Advancement Act (NTTAA)

    This proposed rulemaking does not involve technical standards.

[[Page 20168]]

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action does not have disproportionately 
high and adverse human health or environmental effects on minority 
populations, low-income populations and/or indigenous peoples, as 
specified in Executive Order 12898.\349\ The documentation for this 
decision is contained in Section VIII. Environmental Justice Analytical 
Considerations and Stakeholder Outreach and Engagement of this Proposed 
rule and in Chapter 7, Environmental Justice Impacts of the RIA, which 
is in the public document. The RIA was prepared under E.O. 12866 
Regulatory Planning and Review for this proposed rule. While the ozone 
exposure assessment was subject to several limitations, also described 
in Chapter 7 of the RIA, overall, ozone concentrations under the 
proposal, more stringent, and less stringent alternatives are predicted 
to impact demographic groups very similarly in both future years and 
across both EGUs and non-EGUs.
---------------------------------------------------------------------------

    \349\ 59 FR 7629, February 16, 1994.
---------------------------------------------------------------------------

    Therefore, regarding ozone concentrations, EPA does not find 
evidence of meaningful environmental justice concerns associated with 
ozone concentrations after imposition of the proposed regulatory action 
or alternatives under consideration. We also do not find evidence that 
any potential environmental justice concerns related to ozone would be 
meaningfully exacerbated in the regulatory alternatives under 
consideration, compared to the baseline. Importantly, the action 
described in this proposed rule is expected to lower ozone in many 
areas, including residual ozone nonattainment areas, and thus mitigate 
some pre-existing health risks of ozone across all populations 
evaluated.
    In addition, the EPA provided the public, including those 
communities disproportionately impacted by the burdens of pollution, 
opportunities for meaningful engagement with the EPA on this action. A 
summary of outreach activities conducted by the Agency and what was 
heard from communities is provided in section VIII of this proposed 
rule.

K. Determinations Under CAA Section 307(b)(1) and (d)

    Section 307(b)(1) of the CAA governs judicial review of final 
actions by the EPA. This section provides, in part, that petitions for 
review must be filed in the United States Court of Appeals for the 
District of Columbia Circuit: (i) When the agency action consists of 
``nationally applicable regulations promulgated, or final action taken, 
by the Administrator,'' or (ii) when such action is locally or 
regionally applicable, but ``such action is based on a determination of 
nationwide scope or effect and if in taking such action the 
Administrator finds and publishes that such action is based on such a 
determination.'' For locally or regionally applicable final actions, 
the CAA reserves to EPA complete discretion whether to invoke the 
exception in (ii).
    This proposed action, if finalized, would be ``nationally 
applicable'' within the meaning of CAA section 307(b)(1). In the 
alternative, to the extent a court finds this action to be locally or 
regionally applicable, the Administrator proposes to exercise the 
complete discretion afforded to him under the CAA to make and publish a 
finding that this action is based on a determination of ``nationwide 
scope or effect'' within the meaning of CAA section 307(b)(1).\350\
---------------------------------------------------------------------------

    \350\ In proposing to invoke the exception by making and 
publishing a finding that this final action is based on a 
determination of nationwide scope or effect, the Administrator is 
taking into account a number of policy considerations, including his 
judgment balancing the benefit of obtaining the D.C. Circuit's 
authoritative centralized review versus allowing development of the 
issue in other contexts and the best use of agency resources.
---------------------------------------------------------------------------

    This proposed action, if finalized, will implement the good 
neighbor provision in 26 states, spanning 8 EPA regions and 10 federal 
judicial circuits. The proposed action applies a uniform, nationwide 
analytical method and interpretation of CAA section 110(a)(2)(D)(i)(I) 
across these states, and the proposed rule is based on a common core of 
legal, technical, and policy determinations (as explained in further 
detail in the following paragraph). For these reasons, this proposed 
action is nationally applicable.
    Alternatively, for these same reasons, the Administrator is 
exercising the discretion afforded to him by the CAA and hereby finds 
that this proposed action is based on multiple determinations of 
nationwide scope or effect for purposes of CAA section 307(b)(1).\351\ 
Specifically, the proposed rule is based on a common core of statutory 
and case law analysis, factual findings, and policy determinations 
concerning the transport of ozone-precursor pollutants from the 
different states subject to it, as well as the impacts of those 
pollutants and the impacts of options to address those pollutants in 
yet other states. In this proposed action, EPA is applying its 4-step 
analytic framework to implement the good neighbor provision across 
these states, using a consistent set of policy and analytical 
determinations. The proposed determinations include a nationally 
consistent definition of receptors at Step 1 and findings identifying 
downwind nonattainment and maintenance receptors; the application of a 
nationally consistent contribution threshold at Step 2 to determine 
which states are linked to those receptors and should be further 
evaluated at Step 3; the use of a nationally consistent multi-factor 
test at Step 3 to determine which upwind-state contributions to 
nonattainment and maintenance receptors are ``significant'' and must be 
eliminated; and the proposed implementation at Step 4 of a nationally 
consistent set of emissions control strategies through emissions 
budgets and an integrated interstate emissions trading program for 
EGUs, a nationally consistent set of other compliance requirements for 
EGUs, and a nationally consistent set of enforceable emissions limits 
and associated compliance requirements for certain non-EGU sources in 
several industrial sectors across 23 states. Finally, the technical, 
scientific, and engineering information in support of these proposed 
determinations relies on a nationally consistent set of air quality 
modeling analyses and other nationally consistent analytical methods, 
as set forth elsewhere in this proposed rule and in the relevant 
supporting documents in the docket for this proposed rule.
---------------------------------------------------------------------------

    \351\ In the report on the 1977 Amendments that revised section 
307(b)(1) of the CAA, Congress noted that the Administrator's 
determination that the ``nationwide scope or effect'' exception 
applies would be appropriate for any action that has a scope or 
effect beyond a single judicial circuit. See H.R. Rep. No. 95-294 at 
323, 324, reprinted in 1977 U.S.C.C.A.N. 1402-03.
---------------------------------------------------------------------------

    Therefore, pursuant to CAA section 307(b), any petitions for review 
of this action, if and when it is finalized, must be filed in the D.C. 
Circuit within 60 days from the date such final action is published in 
the Federal Register.
    This action is subject to the provisions of section 307(d). CAA 
section 307(d)(1)(B) provides that section 307(d) applies to, among 
other things, ``the promulgation or revision of an implementation plan 
by the Administrator under [CAA section 110(c)].'' 42 U.S.C. 
7407(d)(1)(B). This action, among other things, proposes new federal 
implementation plans pursuant to the authority of section 110(c). To 
the extent any portion of this rulemaking, if finalized, is not 
expressly identified under section 307(d)(1)(B),

[[Page 20169]]

the Administrator determines that the provisions of section 307(d) 
apply to such final action. See CAA section 307(d)(1)(V) (the 
provisions of section 307(d) apply to ``such other actions as the 
Administrator may determine'').

List of Subjects

40 CFR Part 52

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference, Intergovernmental 
relations, Nitrogen oxides, Ozone, Particulate matter, Sulfur dioxide.

40 CFR Part 75

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Continuous emission monitoring, Electric power 
plants, Incorporation by reference, Nitrogen oxides, Ozone, Particulate 
matter, Reporting and recordkeeping requirements, Sulfur dioxide.

40 CFR Part 78

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Electric power plants, Nitrogen oxides, Ozone, 
Particulate matter, Sulfur dioxide.

40 CFR Part 97

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Electric power plants, Nitrogen oxides, Ozone, 
Particulate matter, Reporting and recordkeeping requirements, Sulfur 
dioxide.

Michael Regan,
Administrator.
    For the reasons stated in the preamble, parts 52, 75, 78, and 97 of 
title 40 of the Code of Federal Regulations are proposed to be amended 
as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

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

Subpart A--General Provisions

0
2. Amend Sec.  52.38 by:
0
a. In paragraph (a)(1), removing ``(NOX), except'' and 
adding in its place ``(NOX) for sources meeting the 
applicability criteria set forth in that subpart, except'';
0
b. In paragraph (a)(4) introductory text, removing ``State's sources, 
and'' and adding in its place ``State, and'';
0
c. In table 1 to paragraph (a)(4)(i)(B), revising the entry for ``2025 
and any year thereafter'';
0
d. In paragraph (a)(5) introductory text, removing ``State (but not 
sources in any Indian country within the borders of the State), 
regulations'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, regulations'';
0
e. In table 2 to paragraph (a)(5)(i)(B), revising the entry for ``2025 
and any year thereafter'';
0
f. In paragraph (a)(5)(iv), removing ``Indian country within the 
borders of the State'' and adding in its place ``areas of Indian 
country within the borders of the State not subject to the State's SIP 
authority'';
0
g. In paragraph (a)(5)(v), removing ``Indian country within the borders 
of the State, the'' and adding in its place ``areas of Indian country 
within the borders of the State not subject to the State's SIP 
authority, the'';
0
h. Revising paragraphs (a)(6) and (a)(7)(ii);
0
i. In paragraph (a)(8)(iii), removing ``State (but not sources in any 
Indian country within the borders of the State):'' and adding in its 
place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority:'';
0
j. In paragraph (b)(1), removing ``year), except'' and adding in its 
place ``year) for sources meeting the applicability criteria set forth 
in those subparts, except'';
0
k. Redesignating paragraphs (b)(2)(i) and (ii)as paragraphs 
(b)(2)(i)(A) and (B), respectively, redesignating paragraphs 
(b)(2)(iii) and (iv) as paragraphs (b)(2)(ii)(A) and (B), respectively, 
and redesignating paragraph (b)(2)(v) as paragraph (b)(2)(iii)(A);
0
l. In newly redesignated paragraph (b)(2)(ii)(A), removing ``Alabama, 
Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Tennessee, 
Texas, and Wisconsin.'' and adding in its place ``Iowa and Kansas.'';
0
m. Adding paragraphs (b)(2)(ii)(C) and (b)(2)(iii)(B) and (C);
0
n. In paragraph (b)(3) introductory text, removing ``or (ii)'';
0
o. Revising paragraph (b)(4) introductory text;
0
p. In table 3 to paragraph (b)(4)(ii)(B), revising the entry for ``2025 
and any year thereafter'';
0
q. Revising paragraph (b)(5) introductory text;
0
r. In table 4 to paragraph (b)(5)(ii)(B), revising the entry for ``2025 
and any year thereafter'';
0
s. In paragraph (b)(5)(v), removing ``Indian country within the borders 
of the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority'';
0
t. In paragraph (b)(5)(vi), removing ``Indian country within the 
borders of the State, the'' and adding in its place ``areas of Indian 
country within the borders of the State not subject to the State's SIP 
authority, the'';
0
u. In paragraph (b)(7) introductory text, removing ``(b)(2)(iii) or 
(iv)'' and adding in its place ``(b)(2)(ii)'';
0
v. Revising paragraph (b)(8) introductory text;
0
w. In paragraph (b)(8)(i), adding ``and'' after the semicolon;
0
x. Removing and reserving paragraph (b)(8)(ii);
0
y. Revising paragraph (b)(8)(iii)(A);
0
z. In table 5 to paragraph (b)(8)(iii)(B), revising the entry for 
``2025 and any year thereafter'';
0
aa. In paragraph (b)(8)(iv), removing ``(b)(8)(i), (ii), or (iii)'' and 
adding in its place ``(b)(8)(i) or (iii)'' each time it appears;
0
bb. Revising paragraph (b)(9) introductory text;
0
cc. Removing and reserving paragraph (b)(9)(ii);
0
dd. Revising paragraph (b)(9)(iii)(A);
0
ee. In table 6 to paragraph (b)(9)(iii)(B), revising the entry for 
``2025 and any year thereafter'';
0
ff. In paragraph (b)(9)(vi), removing ``Indian country within the 
borders of the State'' and adding in its place ``areas of Indian 
country within the borders of the State not subject to the State's SIP 
authority'';
0
gg. Revising paragraph (b)(9)(vii);
0
hh. In paragraph (b)(9)(viii), removing ``(b)(9)(i), (ii), or (iii)'' 
and adding in its place ``(b)(9)(i) or (iii)'';
0
ii. Revising paragraphs (b)(10) introductory text, (b)(10)(i) and (ii), 
(b)(10)(v)(A) and (B), (b)(11) introductory text, (b)(11)(iii) 
introductory text, (b)(11)(iii)(A) introductory text, and 
(b)(11)(iii)(B);
0
jj. Removing and reserving paragraph (b)(11)(iii)(C);
0
kk. Revising paragraph (b)(11)(iii)(D);
0
ll. In paragraph (b)(11)(iv), removing ``paragraphs (b)(11)(iii)(B) and 
(C)'' and adding in its place ``paragraph (b)(11)(iii)(B)'';
0
mm. Revising paragraphs (b)(12) introductory text, (b)(12)(iii) 
introductory text, (b)(12)(iii)(A) introductory text, and 
(b)(12)(iii)(B);
0
nn. Removing and reserving paragraph (b)(12)(iii)(C);
0
oo. Revising paragraphs (b)(12)(iii)(D) and (b)(12)(vi) and (vii);
0
pp. In paragraph (b)(12)(viii), removing ``paragraphs (b)(12)(iii)(B) 
and (C)'' and adding in its place ``paragraph (b)(12)(iii)(B)'';

[[Page 20170]]

0
qq. Revising paragraphs (b)(13) introductory text and (b)(13)(i);
0
rr. In paragraph (b)(13)(ii), removing ``(b)(9)(ii) or'';
0
ss. In paragraph (b)(14)(i)(F), removing ``Sec.  97.825(b)'' and adding 
in its place ``Sec. Sec.  97.806(c)(2) and (3) and 97.825(b)'';
0
tt. In paragraph (b)(14)(i)(G), removing ``Sec.  97.826(e)'' and adding 
in its place ``Sec.  97.826(f)'';
0
uu. Revising paragraphs (b)(14)(ii) and (b)(14)(iii) introductory text;
0
vv. In paragraph (b)(14)(iii)(D), removing ``and'' after the semicolon;
0
ww. In paragraph (b)(14)(iii)(E), removing ``(b)(2)(iv) of this 
section).'' and adding in its place ``(b)(2)(ii)(B) of this 
section);'';
0
xx. Adding paragraphs (b)(14)(iii)(F) and (G);
0
yy. In paragraph (b)(15)(iii), removing ``State (but not sources in any 
Indian country within the borders of the State):'' and adding in its 
place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority:'';
0
zz. In paragraph (b)(16)(i)(B), removing ``Sec.  97.804(a) and (b) 
or'';
0
aaa. Revising paragraph (b)(16)(i)(C);
0
bbb. Redesignating paragraph (b)(16)(ii) as paragraph (b)(16)(ii)(A), 
and in the newly redesignated paragraph, removing ``(b)(2)(iv)'' and 
adding in its place ``(b)(2)(ii)(B)'';
0
ccc. Adding paragraph (b)(16)(ii)(B); and
0
ddd. Revising paragraphs (b)(17)(i) through (iii).
    The revisions and additions read as follows:


Sec.  52.38   What are the requirements of the Federal Implementation 
Plans (FIPs) for the Cross-State Air Pollution Rule (CSAPR) relating to 
emissions of nitrogen oxides?

    (a) * * *
    (4) * * *
    (i) * * *
    (B) * * *

                    Table 1 to Paragraph (a)(4)(i)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR NOX annual allowances are       allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (5) * * *
    (i) * * *
    (B) * * *

                    Table 2 to Paragraph (a)(5)(i)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR NOX annual allowances are       allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (6) Withdrawal of CSAPR FIP provisions relating to NOX annual 
emissions. Except as provided in paragraph (a)(7) of this section, 
following promulgation of an approval by the Administrator of a State's 
SIP revision as correcting the SIP's deficiency that is the basis for 
the CSAPR Federal Implementation Plan set forth in paragraphs (a)(1), 
(a)(2)(i), and (a)(3) and (4) of this section for sources in the State 
and Indian country within the borders of the State, the provisions of 
paragraph (a)(2)(i) of this section will no longer apply to sources in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority, unless the Administrator's 
approval of the SIP revision is partial or conditional, and will 
continue to apply to sources in areas of Indian country within the 
borders of the State not subject to the State's SIP authority, provided 
that if the CSAPR Federal Implementation Plan was promulgated as a 
partial rather than full remedy for an obligation of the State to 
address interstate air pollution, the SIP revision likewise will 
constitute a partial rather than full remedy for the State's obligation 
unless provided otherwise in the Administrator's approval of the SIP 
revision.
    (7) * * *
    (ii) Notwithstanding the provisions of paragraph (a)(6) of this 
section, if, at the time of any approval of a State's SIP revision 
under this section, the Administrator has already started recording any 
allocations of CSAPR NOX Annual allowances under subpart 
AAAAA of part 97 of this chapter to units in the State and areas of 
Indian country within the borders of the State subject to the State's 
SIP authority for a control period in any year, the provisions of such 
subpart authorizing the Administrator to complete the allocation and 
recordation of such allowances to such units for each such control 
period shall continue to apply, unless provided otherwise by such 
approval of the State's SIP revision.
* * * * *
    (b) * * *
    (2) * * *
    (ii) * * *
    (C) The provisions of subpart EEEEE of part 97 of this chapter 
apply to sources in each of the following States and Indian country 
located within the borders of such States with regard to emissions 
occurring in 2017 through 2022 only, except as provided in paragraph 
(b)(14)(iii) of this section: Alabama, Arkansas, Mississippi, Missouri, 
Oklahoma, Tennessee, Texas, and Wisconsin.
    (iii) * * *
    (B) The provisions of subpart GGGGG of part 97 of this chapter 
apply to sources in each of the following States and Indian country 
located within the borders of such States with regard to emissions 
occurring in 2023 and each subsequent year: Alabama, Arkansas, 
Mississippi, Missouri, Oklahoma, Tennessee, Texas, and Wisconsin.
    (C) The provisions of subpart GGGGG of part 97 of this chapter 
apply to sources in each of the following States and Indian country 
located within the borders of such States with regard to

[[Page 20171]]

emissions occurring on and after [EFFECTIVE DATE OF FINAL RULE] and in 
each subsequent year: Delaware, Minnesota, Nevada, Utah, and Wyoming.
* * * * *
    (4) Abbreviated SIP revisions replacing certain provisions of the 
federal CSAPR NOX Ozone Season Group 1 Trading Program. A State listed 
in paragraph (b)(2)(i)(A) of this section may adopt and include in a 
SIP revision, and the Administrator will approve, regulations replacing 
specified provisions of subpart BBBBB of part 97 of this chapter for 
the State, and not substantively replacing any other provisions, as 
follows:
* * * * *
    (ii) * * *
    (B) * * *

                   Table 3 to Paragraph (b)(4)(ii)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
     CSAPR NOX ozone season Group 1       allocations or auction results
 allowances are allocated or auctioned         to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (5) Full SIP revisions adopting State CSAPR NOX Ozone Season Group 
1 Trading Programs. A State listed in paragraph (b)(2)(i)(A) of this 
section may adopt and include in a SIP revision, and the Administrator 
will approve, as correcting the deficiency in the SIP that is the basis 
for the CSAPR Federal Implementation Plan set forth in paragraphs 
(b)(1), (b)(2)(i), and (b)(3) and (4) of this section with regard to 
sources in the State and areas of Indian country within the borders of 
the State subject to the State's SIP authority, regulations that are 
substantively identical to the provisions of the CSAPR NOX 
Ozone Season Group 1 Trading Program set forth in Sec. Sec.  97.502 
through 97.535 of this chapter, except that the SIP revision:
* * * * *
    (ii) * * *
    (B) * * *

                   Table 4 to Paragraph (b)(5)(ii)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
     CSAPR NOX ozone season Group 1       allocations or auction results
 allowances are allocated or auctioned         to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (8) Abbreviated SIP revisions replacing certain provisions of the 
federal CSAPR NOX Ozone Season Group 2 Trading Program. A State listed 
in paragraph (b)(2)(ii) of this section may adopt and include in a SIP 
revision, and the Administrator will approve, regulations replacing 
specified provisions of subpart EEEEE of part 97 of this chapter for 
the State, and not substantively replacing any other provisions, as 
follows:
* * * * *
    (iii) * * *
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of CSAPR NOX Ozone 
Season Group 2 allowances for any such control period not exceeding the 
amount, under Sec. Sec.  97.810(a) and 97.821 of this chapter for the 
State and such control period, of the CSAPR NOX Ozone Season 
Group 2 trading budget minus the sum of the Indian country new unit 
set-aside and the amount of any CSAPR NOX Ozone Season Group 
2 allowances already allocated and recorded by the Administrator;
    (B) * * *

                   Table 5 to Paragraph (b)(8)(iii)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
     CSAPR NOX ozone season Group 2       allocations or auction results
 allowances are allocated or auctioned         to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (9) Full SIP revisions adopting State CSAPR NOX Ozone Season Group 
2 Trading Programs. A State listed in paragraph (b)(2)(ii) of this 
section may adopt and include in a SIP revision, and the Administrator 
will approve, as correcting the deficiency in the SIP that is the basis 
for the CSAPR Federal Implementation Plan set forth in paragraphs 
(b)(1), (b)(2)(ii), and (b)(7) and (8) of this section with regard to 
sources in the State and areas of Indian country within the borders of 
the State subject to the State's SIP authority, regulations that are 
substantively identical to the provisions of the CSAPR NOX 
Ozone Season Group 2 Trading Program set forth in Sec. Sec.  97.802 
through 97.835 of this chapter, except that the SIP revision:
* * * * *
    (iii) * * *
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of CSAPR NOX Ozone 
Season Group 2 allowances for any such control period not exceeding the 
amount, under

[[Page 20172]]

Sec. Sec.  97.810(a) and 97.821 of this chapter for the State and such 
control period, of the CSAPR NOX Ozone Season Group 2 
trading budget minus the sum of the Indian country new unit set-aside 
and the amount of any CSAPR NOX Ozone Season Group 2 
allowances already allocated and recorded by the Administrator;
    (B) * * *

                   Table 6 to Paragraph (b)(9)(iii)(B)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
     CSAPR NOX ozone season Group 2       allocations or auction results
 allowances are allocated or auctioned         to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (vii) Provided that, if and when any covered unit is located in 
areas of Indian country within the borders of the State not subject to 
the State's SIP authority, the Administrator may modify his or her 
approval of the SIP revision to exclude the provisions in Sec. Sec.  
97.802 (definitions of ``common designated representative'', ``common 
designated representative's assurance level'', and ``common designated 
representative's share''), 97.806(c)(2), and 97.825 of this chapter and 
the portions of other provisions of subpart EEEEE of part 97 of this 
chapter referencing these sections and may modify any portion of the 
CSAPR Federal Implementation Plan that is not replaced by the SIP 
revision to include these provisions; and
* * * * *
    (10) State-determined allocations of CSAPR NOX Ozone 
Season Group 3 allowances for 2024. A State listed in paragraph 
(b)(2)(iii) of this section may adopt and include in a SIP revision, 
and the Administrator will approve, as CSAPR NOX Ozone 
Season Group 3 allowance allocation provisions replacing the provisions 
in Sec.  97.1011(a)(1) of this chapter with regard to the State and the 
control period in 2024, a list of CSAPR NOX Ozone Season 
Group 3 units and the amount of CSAPR NOX Ozone Season Group 
3 allowances allocated to each unit on such list, provided that the 
list of units and allocations meets the following requirements:
    (i) All of the units on the list must be units that are in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority and that commenced commercial 
operation before January 1, 2021;
    (ii) The total amount of CSAPR NOX Ozone Season Group 3 
allowance allocations on the list must not exceed the amount, under 
Sec.  97.1010 of this chapter for the State and the control period in 
2024, of the CSAPR NOX Ozone Season Group 3 trading budget 
minus the sum of the new unit set-aside and Indian country existing 
unit set-aside;
* * * * *
    (v) * * *
    (A) By [EFFECTIVE DATE OF FINAL RULE], the State must notify the 
Administrator electronically in a format specified by the Administrator 
of the State's intent to submit to the Administrator a complete SIP 
revision meeting the requirements of paragraphs (b)(10)(i) through (iv) 
of this section by September 1, 2023; and
    (B) The State must submit to the Administrator a complete SIP 
revision described in paragraph (b)(10)(v)(A) of this section by 
September 1, 2023.
    (11) Abbreviated SIP revisions replacing certain provisions of the 
federal CSAPR NOX Ozone Season Group 3 Trading Program. A State listed 
in paragraph (b)(2)(iii) of this section may adopt and include in a SIP 
revision, and the Administrator will approve, regulations replacing 
specified provisions of subpart GGGGG of part 97 of this chapter for 
the State, and not substantively replacing any other provisions, as 
follows:
* * * * *
    (iii) The State may adopt, as CSAPR NOX Ozone Season 
Group 3 allowance allocation or auction provisions replacing the 
provisions in Sec.  97.1011(a)(1) of this chapter with regard to the 
State and the control period in 2025 or any subsequent year, any 
methodology under which the State or the permitting authority allocates 
or auctions CSAPR NOX Ozone Season Group 3 allowances and 
may adopt, in addition to the definitions in Sec.  97.1002 of this 
chapter, one or more definitions that shall apply only to terms as used 
in the adopted CSAPR NOX Ozone Season Group 3 allowance 
allocation or auction provisions, if such methodology--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of CSAPR NOX Ozone 
Season Group 3 allowances for any such control period not exceeding the 
amount, under Sec. Sec.  97.1010 and 97.1021 of this chapter for the 
State and such control period, of the CSAPR NOX Ozone Season 
Group 3 trading budget minus the sum of the new unit set-aside, the 
Indian country existing unit set-aside, and the amount of any CSAPR 
NOX Ozone Season Group 3 allowances already allocated and 
recorded by the Administrator, plus, if the State adopts regulations 
expanding applicability to additional units pursuant to paragraph 
(b)(11)(ii) of this section, an additional amount of CSAPR 
NOX Ozone Season Group 3 allowances not exceeding the lesser 
of:
* * * * *
    (B) Requires, to the extent the State adopts provisions for 
allocations or auctions of CSAPR NOX Ozone Season Group 3 
allowances for any such control period to any CSAPR NOX 
Ozone Season Group 3 units covered by Sec.  97.1011(a)(1) of this 
chapter, that the State or the permitting authority submit such 
allocations or the results of such auctions for such control period 
(except allocations or results of auctions to such units of CSAPR 
NOX Ozone Season Group 3 allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator by June 1 of the year before the year 
of such control period; and
* * * * *
    (D) Does not provide for any change, after the submission deadlines 
in paragraph (b)(11)(iii)(B) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in any allocation determined and recorded by the 
Administrator under subpart GGGGG of part 97 of this chapter or Sec.  
97.526(d) or Sec.  97.826(d) or (e) of this chapter;
* * * * *
    (12) Full SIP revisions adopting State CSAPR NOX Ozone Season Group 
3 Trading Programs. A State listed in paragraph (b)(2)(iii) of this 
section may adopt and include in a SIP revision, and the Administrator 
will approve, as correcting the deficiency in the SIP that is the basis 
for the CSAPR Federal

[[Page 20173]]

Implementation Plan set forth in paragraphs (b)(1), (b)(2)(iii), and 
(b)(10) and (11) of this section with regard to sources in the State 
and areas of Indian country within the borders of the State subject to 
the State's SIP authority, regulations that are substantively identical 
to the provisions of the CSAPR NOX Ozone Season Group 3 
Trading Program set forth in Sec. Sec.  97.1002 through 97.1035 of this 
chapter, except that the SIP revision:
* * * * *
    (iii) May adopt, as CSAPR NOX Ozone Season Group 3 
allowance allocation provisions replacing the provisions in Sec.  
97.1011(a)(1) of this chapter with regard to the State and the control 
period in 2025 or any subsequent year, any methodology under which the 
State or the permitting authority allocates or auctions CSAPR 
NOX Ozone Season Group 3 allowances and that--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of CSAPR NOX Ozone 
Season Group 3 allowances for any such control period not exceeding the 
amount, under Sec. Sec.  97.1010 and 97.1021 of this chapter for the 
State and such control period, of the CSAPR NOX Ozone Season 
Group 3 trading budget minus the sum of the new unit set-aside, the 
Indian country existing unit set-aside, and the amount of any CSAPR 
NOX Ozone Season Group 3 allowances already allocated and 
recorded by the Administrator, plus, if the State adopts regulations 
expanding applicability to additional units pursuant to paragraph 
(b)(12)(ii) of this section, an additional amount of CSAPR 
NOX Ozone Season Group 3 allowances not exceeding the lesser 
of:
* * * * *
    (B) Requires, to the extent the State adopts provisions for 
allocations or auctions of CSAPR NOX Ozone Season Group 3 
allowances for any such control period to any CSAPR NOX 
Ozone Season Group 3 units covered by Sec.  97.1011(a)(1) of this 
chapter, that the State or the permitting authority submit such 
allocations or the results of such auctions for such control period 
(except allocations or results of auctions to such units of CSAPR 
NOX Ozone Season Group 3 allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator by June 1 of the year before the year 
of such control period; and
* * * * *
    (D) Does not provide for any change, after the submission deadlines 
in paragraph (b)(12)(iii)(B) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in any allocation determined and recorded by the 
Administrator under subpart GGGGG of part 97 of this chapter or Sec.  
97.526(d) or Sec.  97.826(d) or (e) of this chapter;
* * * * *
    (vi) Must not include any of the requirements imposed on any unit 
in areas of Indian country within the borders of the State not subject 
to the State's SIP authority in the provisions in Sec. Sec.  97.1002 
through 97.1035 of this chapter and must not include the provisions in 
Sec. Sec.  97.1011(a)(2), 97.1012, and 97.1021(g) through (j) of this 
chapter, all of which provisions will continue to apply under the 
portion of the CSAPR Federal Implementation Plan that is not replaced 
by the SIP revision;
    (vii) Provided that, if any covered unit is located in areas of 
Indian country within the borders of the State not subject to the 
State's SIP authority before the Administrator's approval of the SIP 
revision, the SIP revision must exclude the provisions in Sec. Sec.  
97.1002 (definitions of ``base CSAPR NOX Ozone Season Group 
3 source'', ``base CSAPR NOX Ozone Season Group 3 unit'', 
``common designated representative'', ``common designated 
representative's assurance level'', and ``common designated 
representative's share''), 97.1006(c)(2), and 97.1025 of this chapter 
and the portions of other provisions of subpart GGGGG of part 97 of 
this chapter referencing these sections, and further provided that, if 
and when any covered unit is located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority after 
the Administrator's approval of the SIP revision, the Administrator may 
modify his or her approval of the SIP revision to exclude these 
provisions and may modify any portion of the CSAPR Federal 
Implementation Plan that is not replaced by the SIP revision to include 
these provisions; and
* * * * *
    (13) Withdrawal of CSAPR FIP provisions relating to NOX ozone 
season emissions; satisfaction of NOX SIP Call requirements. Following 
promulgation of an approval by the Administrator of a State's SIP 
revision as correcting the SIP's deficiency that is the basis for the 
CSAPR Federal Implementation Plan set forth in paragraphs (b)(1), 
(b)(2)(i), and (b)(3) and (4) of this section, paragraphs (b)(1), 
(b)(2)(ii), and (b)(7) and (8) of this section, or paragraphs (b)(1), 
(b)(2)(iii), and (b)(10) and (11) of this section for sources in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority--
    (i) Except as provided in paragraph (b)(14) of this section, the 
provisions of paragraph (b)(2)(i), (ii), or (iii) of this section, as 
applicable, will no longer apply to sources in the State and areas of 
Indian country within the borders of the State subject to the State's 
SIP authority, unless the Administrator's approval of the SIP revision 
is partial or conditional, and will continue to apply to sources in 
areas of Indian country within the borders of the State not subject to 
the State's SIP authority, provided that if the CSAPR Federal 
Implementation Plan was promulgated as a partial rather than full 
remedy for an obligation of the State to address interstate air 
pollution, the SIP revision likewise will constitute a partial rather 
than full remedy for the State's obligation unless provided otherwise 
in the Administrator's approval of the SIP revision; and
* * * * *
    (14) * * *
    (ii) Notwithstanding the provisions of paragraph (b)(13)(i) of this 
section, if, at the time of any approval of a State's SIP revision 
under this section, the Administrator has already started recording any 
allocations of CSAPR NOX Ozone Season Group 1 allowances 
under subpart BBBBB of part 97 of this chapter, or allocations of CSAPR 
NOX Ozone Season Group 2 allowances under subpart EEEEE of 
part 97 of this chapter, or allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter, to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of such subpart authorizing the 
Administrator to complete the allocation and recordation of such 
allowances to such units for each such control period shall continue to 
apply, unless provided otherwise by such approval of the State's SIP 
revision.
    (iii) Notwithstanding any discontinuation of the applicability of 
subpart BBBBB or EEEEE of part 97 of this chapter to the sources in a 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority with regard to emissions occurring 
in any control period pursuant to paragraph (b)(2)(i)(B), (b)(2)(ii)(B) 
or (C), or (b)(13)(i) of this section, the following provisions shall 
continue to apply with regard to all CSAPR NOX Ozone Season 
Group 1 allowances and CSAPR NOX Ozone Season Group 2 
allowances at any time

[[Page 20174]]

allocated for any control period to any source or other entity in the 
State and shall apply to all entities, wherever located, that at any 
time held or hold such allowances:
* * * * *
    (F) The provisions of Sec.  97.826(e) of this chapter (concerning 
the conversion of amounts of unused CSAPR NOX Ozone Season 
Group 2 allowances allocated for control periods before 2023 to 
different amounts of CSAPR NOX Ozone Season Group 3 
allowances); and
    (G) The provisions of Sec.  97.811(e) of this chapter (concerning 
the recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all CSAPR NOX Ozone 
Season Group 2 allowances allocated for control periods after 2022 and 
recorded in the compliance accounts of sources in States listed in 
paragraph (b)(2)(ii)(C) of this section).
* * * * *
    (16) * * *
    (i) * * *
    (C) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(9) of this section as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan set forth in paragraphs (b)(1), (b)(2)(ii), and 
(b)(7) and (8) of this section with regard to sources in the State and 
areas of Indian country within the borders of the State subject to the 
State's SIP authority: Alabama, Indiana, and Missouri.
    (ii) * * *
    (B) Notwithstanding any provision of subpart EEEEE of part 97 of 
this chapter or any State's SIP, with regard to any State listed in 
paragraph (b)(2)(ii)(C) of this section and any control period that 
begins after December 31, 2022, the Administrator will not carry out 
any of the functions set forth for the Administrator in subpart EEEEE 
of part 97 of this chapter, except Sec. Sec.  97.811(e) and 97.826(c) 
and (e) of this chapter, or in any emissions trading program provisions 
in a State's SIP approved under paragraph (b)(8) or (9) of this 
section.
    (17) * * *
    (i) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(10) of this section as 
replacing the CSAPR NOX Ozone Season Group 3 allowance 
allocation provisions in Sec.  97.1011(a)(1) of this chapter with 
regard to the State and the control period in 2024: [none].
    (ii) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(11) of this section as 
replacing the CSAPR NOX Ozone Season Group 3 applicability 
provisions in Sec.  97.1004(a) and (b) or Sec.  97.1004(a)(1) and (2) 
of this chapter or the CSAPR NOX Ozone Season Group 2 
allowance allocation provisions in Sec.  97.1011(a)(1) of this chapter 
with regard to the State and the control period in 2025 or any 
subsequent year: [none].
    (iii) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(12) of this section as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan set forth in paragraphs (b)(1), (b)(2)(iii), and 
(b)(10) and (11) of this section with regard to sources in the State 
and areas of Indian country within the borders of the State subject to 
the State's SIP authority: [none].
0
3. Amend Sec.  52.39 by:
0
a. In paragraph (a), removing ``(SO2), except'' and adding 
in its place ``(SO2) for sources meeting the applicability 
criteria set forth in those subparts, except'';
0
b. In paragraph (e) introductory text, removing ``State's sources, 
and'' and adding in its place ``State, and'';
0
c. In table 1 to paragraph (e)(1)(ii), revising the entry for ``2025 
and any year thereafter'';
0
d. In paragraph (f) introductory text, removing ``State (but not 
sources in any Indian country within the borders of the State), 
regulations'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, regulations'';
0
e. In table 2 to paragraph (f)(1)(ii), revising the entry for ``2025 
and any year thereafter'';
0
f. In paragraph (f)(4), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority'';
0
g. In paragraph (f)(5), removing ``Indian country within the borders of 
the State, the'' and adding in its place ``areas of Indian country 
within the borders of the State not subject to the State's SIP 
authority, the'';
0
h. In paragraph (h) introductory text, removing ``State's sources, 
and'' and adding in its place ``State, and'';
0
i. In table 3 to paragraph (h)(1)(ii), revising the entry for ``2025 
and any year thereafter'';
0
j. In paragraph (i) introductory text, removing ``State (but not 
sources in any Indian country within the borders of the State), 
regulations'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, regulations'';
0
k. In table 4 to paragraph (i)(1)(ii), revising the entry for ``2025 
and any year thereafter'';
0
l. In paragraph (i)(4), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority'';
0
m. In paragraph (i)(5), removing ``Indian country within the borders of 
the State, the'' and adding in its place ``areas of Indian country 
within the borders of the State not subject to the State's SIP 
authority, the'';
0
n. Revising paragraphs (j) and (k)(2); and
0
o. In paragraphs (l)(3) and (m)(3), removing ``State (but not sources 
in any Indian country within the borders of the State):'' and adding in 
its place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority:''.
    The revisions read as follows:


Sec.  52.39   What are the requirements of the Federal Implementation 
Plans (FIPs) for the Cross-State Air Pollution Rule (CSAPR) relating to 
emissions of sulfur dioxide?

* * * * *
    (e) * * *
    (1) * * *
    (ii) * * *

                     Table 1 to Paragraph (e)(1)(ii)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR SO2 Group 1 allowances are      allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------


[[Page 20175]]

* * * * *
    (f) * * *
    (i) * * *
    (ii) * * *

                     Table 2 to Paragraph (f)(1)(ii)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR SO2 Group 1 allowances are      allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (h) * * *
    (1) * * *
    (ii) * * *

                     Table 3 to Paragraph (h)(1)(ii)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR SO2 Group 2 allowances are      allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (i) * * *
    (1) * * *
    (ii) * * *

                     Table 4 to Paragraph (i)(1)(ii)
------------------------------------------------------------------------
  Year of the control period for which      Deadline for submission of
    CSAPR SO2 Group 2 allowances are      allocations or auction results
         allocated or auctioned                to the Administrator
------------------------------------------------------------------------
 
                              * * * * * * *
2025 and any year thereafter...........  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (j) Withdrawal of CSAPR FIP provisions relating to SO2 emissions. 
Except as provided in paragraph (k) of this section, following 
promulgation of an approval by the Administrator of a State's SIP 
revision as correcting the SIP's deficiency that is the basis for the 
CSAPR Federal Implementation Plan set forth in paragraphs (a), (b), 
(d), and (e) of this section or paragraphs (a), (c)(1), (g), and (h) of 
this section for sources in the State and Indian country within the 
borders of the State, the provisions of paragraph (b) or (c)(1) of this 
section, as applicable, will no longer apply to sources in the State 
and areas of Indian country within the borders of the State subject to 
the State's SIP authority, unless the Administrator's approval of the 
SIP revision is partial or conditional, and will continue to apply to 
sources in areas of Indian country within the borders of the State not 
subject to the State's SIP authority, provided that if the CSAPR 
Federal Implementation Plan was promulgated as a partial rather than 
full remedy for an obligation of the State to address interstate air 
pollution, the SIP revision likewise will constitute a partial rather 
than full remedy for the State's obligation unless provided otherwise 
in the Administrator's approval of the SIP revision.
    (k) * * *
    (2) Notwithstanding the provisions of paragraph (j) of this 
section, if, at the time of any approval of a State's SIP revision 
under this section, the Administrator has already started recording any 
allocations of CSAPR SO2 Group 1 allowances under subpart 
CCCCC of part 97 of this chapter, or allocations of CSAPR 
SO2 Group 2 allowances under subpart DDDDD of part 97 of 
this chapter, to units in the State and areas of Indian country within 
the borders of the State subject to the State's SIP authority for a 
control period in any year, the provisions of such subpart authorizing 
the Administrator to complete the allocation and recordation of such 
allowances to such units for each such control period shall continue to 
apply, unless provided otherwise by such approval of the State's SIP 
revision.
* * * * *
0
4. Add Sec. Sec.  52.40 through 52.45 to read as follows:
* * * * *
Sec.
52.40 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
sources not subject to the CSAPR ozone season trading program?
52.41 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
the Pipeline Transportation of Natural Gas Industry?
52.42 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
the Cement and Concrete Product Manufacturing Industry?
52.43 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
the Iron and Steel Mills and Ferroalloy Manufacturing Industry?

[[Page 20176]]

52.44 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
the Glass and Glass Product Manufacturing Industry?
52.45 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
the Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills Industries?
* * * * *


Sec.  52.40   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
sources not subject to the CSAPR ozone season trading program?

    (a) NOX ozone season emissions. This section establishes Federal 
Implementation Plan requirements for new and existing units in the 
industries specified in paragraph (b) of this section to eliminate 
significant contribution to nonattainment, or interference with 
maintenance, of the 2015 8-hour ozone National Ambient Air Quality 
Standards in other states pursuant to 42 U.S.C. 7410(a)(2)(D)(i)(I).
    (b) General requirements (1) The NOX emissions 
limitations and associated compliance requirements for the following 
listed source categories not subject to the CSAPR ozone season trading 
program constitute the Federal Implementation Plan provisions that 
relate to emissions of NOX during the ozone season (defined 
as May 1 through September 30 of a calendar year): Sec.  52.41 for 
engines in the Pipeline Transportation of Natural Gas Industry, Sec.  
52.42 for kilns in the Cement and Concrete Product Manufacturing 
Industry, Sec.  52.43 for units in the Iron and Steel Mills and 
Ferroalloy Manufacturing Industry, Sec.  52.44 for units in the Glass 
and Glass Product Manufacturing Industry, Sec.  52.45 for boilers in 
Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills.
    (2) The provisions of Sec. Sec.  52.41 through 52.45 of this part 
apply to sources located in each of the following States, including 
Indian country located within the borders of such States, beginning in 
the 2026 ozone season and in each subsequent ozone season: Arkansas, 
California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, 
Wisconsin, and Wyoming.
    (3) The owner or operator of an affected unit subject to the 
provisions of Sec. Sec.  52.40 through 52.45 shall maintain files of 
all information (including all reports and notifications) required by 
these sections recorded in a form suitable and readily available for 
expeditious inspection and review. The files shall be retained for at 
least 5 years following the date of each occurrence, measurement, 
maintenance, corrective action, report, or record. At a minimum, the 
most recent 2 years of data shall be retained on site. The remaining 3 
years of data may be retained off site. Such files may be maintained on 
microfilm, on a computer, on computer floppy disks, on magnetic tape 
disks, or on microfiche.


Sec.  52.41   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
the Pipeline Transportation of Natural Gas Industry?

    (a) Definitions. All terms not defined herein shall have the 
meaning given them in the Act and in subpart A of part 60.
    Affected unit means an engine meeting the applicability criteria of 
this section.
    Four stroke means any type of engine which completes the power 
cycle in two crankshaft revolutions, with intake and compression 
strokes in the first revolution and power and exhaust strokes in the 
second revolution.
    ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative 
humidity and 101.3 kilopascals pressure.
    Lean burn means any two[hyphen]stroke or four[hyphen]stroke spark 
ignited reciprocating internal combustion engine that does not meet the 
definition of a rich burn engine.
    Nameplate rating means the manufacturer's design maximum capacity 
in horsepower (hp) at the installation site conditions. Starting from 
the completion of any physical change in the engine resulting in an 
increase in the maximum output (in hp) that the engine is capable of 
producing on a steady state basis and during continuous operation, such 
increased maximum output shall be as specified by the person conducting 
the physical change.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane) or non-hydrocarbons, composed of at least 70 
percent methane by volume or that has a gross calorific value between 
35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 
Btu per dry standard cubic foot), that maintains a gaseous state under 
ISO conditions. Natural gas does not include the following gaseous 
fuels: Landfill gas, digester gas, refinery gas, sour gas, blast 
furnace gas, coal-derived gas, producer gas, coke oven gas, or any 
gaseous fuel produced in a process which might result in highly 
variable CO2 content or heating value.
    Natural gas-fired means that greater than or equal to 90% of the 
engine's heat input, excluding recirculated or recuperated exhaust 
heat, is derived from the combustion of natural gas.
    Operator means any person who operates, controls, or supervises a 
natural gas-fired engine subject to this regulation and shall include, 
but not be limited to, any holding company, utility system, or plant 
manager of such natural gas-fired engine.
    Owner means any holder of any portion of the legal or equitable 
title in a natural gas-fired engine subject to this regulation.
    Pipeline transportation of natural gas means the movement of 
natural gas through an interconnected network of compressors and 
pipeline components, from field gathering networks near wellheads to 
end users, including:
    (i) The compressor and pipeline network used for field gathering of 
natural gas from the wellheads for delivery to either processing 
facilities or connections to pipelines used for intrastate or 
interstate transportation of the natural gas; and
    (ii) The compressor and pipeline network used to transport the 
natural gas from field gathering networks or processing facilities over 
a distance (intrastate or interstate) to and from storage facilities, 
to large natural gas end-users, and to distribution organizations that 
provide the natural gas to end-users.
    Reciprocating internal combustion engine means a reciprocating 
engine in which power, produced by heat and/or pressure that is 
developed in the engine combustion chambers by the burning of a mixture 
of air and fuel, is subsequently converted to mechanical work.
    Rich burn means any four-stroke spark ignited reciprocating 
internal combustion engine where the manufacturer's recommended 
operating air/fuel ratio divided by the stoichiometric air/fuel ratio 
at full load conditions is less than or equal to 1.1. Internal 
combustion engines originally manufactured as rich burn engines but 
modified with passive emission control technology for nitrogen oxides 
(NOX) (such as pre-combustion chambers) will be considered 
lean burn engines. Existing internal combustion engines where there are 
no manufacturer's recommendations regarding air/fuel ratio will be 
considered rich burn engines if the excess oxygen content of

[[Page 20177]]

the exhaust at full load conditions is less than or equal to 2 percent.
    Spark ignition means a reciprocating internal combustion engine 
utilizing a spark plug (or other sparking device) to ignite the air/
fuel mixture and with operating characteristics significantly similar 
to the theoretical Otto combustion cycle.
    Stoichiometric means the theoretical air-to-fuel ratio required for 
complete combustion.
    Two stroke means a type of reciprocating internal combustion engine 
which completes the power cycle in a single crankshaft revolution by 
combining the intake and compression operations into one stroke (one-
half revolution) and the power and exhaust operations into a second 
stroke. This system requires auxiliary exhaust scavenging of the 
combustion products and inherently runs lean (excess of air) of 
stoichiometry.
    (b) Applicability. You are subject to the requirements under this 
section if you own or operate a new or existing natural gas-fired spark 
ignition engine with a nameplate rating of 1,000 hp or greater that is 
used for pipeline transportation of natural gas and is located within 
any of the States listed in Sec.  52.40(a)(1)(ii), including Indian 
country located within the borders of any such State(s).
    (c) Emissions limitations. Beginning with the 2026 ozone season and 
in each ozone season thereafter, the following emissions limitations 
must be met. Compliance with the numerical emissions limitations 
established in this section is based on the average of three 1-hour 
runs using the testing requirements and procedures in paragraph (d) of 
this section.
    (1) If you own or operate a natural gas fired four stroke rich burn 
spark ignition engine with a nameplate rating of 1,000 hp or greater 
than you must meet a nitrogen oxides (NOX) emissions limits 
of 1.0 grams per hp-hour (g/hp-hr).
    (2) If you own or operate a natural gas fired four stroke lean burn 
spark ignition engine with a nameplate rating of 1,000 hp or greater 
than you must meet a NOX emissions limits of 1.5 g/hp-hr.
    (3) If you own or operate a natural gas fired two stroke lean spark 
ignition engine with a nameplate rating of 1,000 hp or greater than you 
must meet a NOX emissions limits of 3.0 g/hp-hr.
    (d) Testing and monitoring requirements (1) If you are an owner or 
operator of a natural gas fired spark ignition engine subject to a 
NOX emissions limit under paragraph (b) of this section, you 
must keep a maintenance plan and records of conducted maintenance and 
must, to the extent practicable, maintain and operate the engine in a 
manner consistent with good air pollution control practice for 
minimizing emissions.
    (2) Performance Testing Requirements:
    (i) Engines that meet the certification requirements of Sec.  
60.4243(a) need not conduct any performance tests, consistent with the 
requirements of 40 CFR part 60, subpart JJJJ.
    (ii) For non-certified engines, the following performance testing 
requirements apply:
    (A) New engines must conduct an initial performance test within six 
months of engine startup and conduct subsequent performance testing 
every six months thereafter to demonstrate compliance.
    (B) Existing engines must conduct an initial performance test 
within six months of becoming subject to an emissions limit under 
paragraph (b) of this section and conduct subsequent performance 
testing every six months thereafter to demonstrate compliance.
    (iii) Performance tests must be conducted in accordance with the 
applicable reference test methods of 40 CFR part 60, appendix A, any 
alternative test method approved by EPA as of April 6, 2022 under 40 
CFR 59.104(f), 60.8(b)(3), 61.13(h)(1)(ii), 63.7(e)(2)(ii), or 
65.158(a)(2) and available at EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods 
and procedures approved by EPA through notice-and-comment rulemaking.
    (3) If a selective catalytic reduction (SCR) or non-selective 
catalytic reduction (NSCR) control device is used to reduce emissions:
    (i) Monitor the inlet temperature to the catalyst daily and conduct 
maintenance if the temperature is not within the observed inlet 
temperature range from the most recent performance test or the 
temperatures specified by the manufacturer if no performance test was 
required by this section.
    (ii) Measure the pressure drop across the catalyst monthly and 
conduct maintenance if the pressure drop is greater than 2 inches 
outside the baseline value established after each semiannual portable 
analyzer monitoring.
    (iii) Engines that are subject to catalyst temperatures and 
catalyst pressure drop monitoring requirements under 40 CFR part 63, 
subpart ZZZZ must satisfy the requirements of Sec.  52.41(d)(3).
    (4) If you are not using a SCR or NSCR control device to reduce 
emissions are required to install a continuous parameter monitoring 
system (CPMS). You must install, operate, and maintain each CPMS 
according to the requirements in paragraphs (d)(4)(i) through (vi) of 
this section.
    (i) You must prepare a site-specific monitoring plan that addresses 
the monitoring system design, data collection, and quality assurance 
and quality control elements outlined in paragraphs (d)(4)(i)(A) 
through (E) of this section.
    (A) The performance criteria and design specifications for the 
monitoring system equipment, including the sample interface, detector 
signal analyzer, and data acquisition and calculations.
    (B) Sampling interface (e.g., thermocouple) location such that the 
monitoring system will provide representative measurements.
    (C) Equipment performance evaluations, system accuracy audits, or 
other audit procedures.
    (D) Ongoing operation and maintenance procedures in accordance with 
the requirements of paragraph (d)(1) of this section.
    (E) Ongoing recordkeeping and reporting procedures in accordance 
with the requirements of paragraphs (e) and (f) of this section.
    (ii) Install, operate, and maintain each CPMS in continuous 
operation according to the procedures in your site-specific monitoring 
plan.
    (iii) The CPMS must collect data at least once every 15 minutes.
    (iv) For a CPMS for measuring temperature range, the temperature 
sensor must have a minimum tolerance of 2.8 degrees Celsius (5 degrees 
Fahrenheit) or 1 percent of the measurement range, whichever is larger.
    (v) You must conduct the CPMS equipment performance evaluation, 
system accuracy audits, or other audit procedures specified in your 
site-specific monitoring plan at least annually.
    (vi) You must conduct a performance evaluation of each CPMS in 
accordance with your site-specific monitoring plan.
    (e) Recordkeeping requirements (1) You must keep records of:
    (i) Performance tests conducted pursuant to Sec.  52.41(d)(2), 
including the date, engine settings on the date of the test, and 
documentation of the methods and results of the testing.
    (ii) Catalyst monitoring required by Sec.  52.41(d)(3), if 
applicable, and any actions taken to address monitored values outside 
the temperature or pressure drop parameters, including the date and a 
description of actions taken.

[[Page 20178]]

    (iii) Parameters monitored pursuant to your site-specific 
monitoring plan for your CPMS.
    (iv) Hours of operation on a daily basis.
    (v) Tuning, adjustments, or other combustion process adjustments 
and the date of the adjustment(s).
    (2) Any records required to be maintained by this section that are 
submitted electronically via the EPA's Compliance and Emissions Data 
Reporting Interface (CEDRI) may be maintained in electronic format. 
This ability to maintain electronic copies does not affect the 
requirement for facilities to make records, data, and reports available 
upon request to the EPA as part of an on-site compliance evaluation.
    (f) Reporting requirements (1) Within 60 days after the date of 
completing each performance test required by this section, you must 
submit the results of the performance test following the procedures 
specified in paragraphs (f)(1)(i) through (iii):
    (i) Data collected using test methods supported by the EPA's 
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website 
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test. Submit the results of the 
performance test to the EPA via the CEDRI or analogous electronic 
reporting approach provided by the EPA to report data required by this 
section, which can be accessed through the EPA's Central Data Exchange 
(CDX) (https://cdx.epa.gov/). The data must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the extensible markup language (XML) 
schema listed on the EPA's ERT website.
    (ii) Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test. The results of the performance test must be included as an 
attachment in the ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT website. Submit the ERT 
generated package or alternative file to the EPA via CEDRI.
    (iii) Confidential business information (CBI). Do not use CEDRI to 
submit information you claim as CBI. Anything submitted using CEDRI 
cannot later be claimed CBI. Although we do not expect persons to 
assert a claim of CBI, if you wish to assert a CBI claim for some of 
the information submitted under paragraphs (f)(1)(i) or (ii) of this 
section, you must submit a complete file, including information claimed 
to be CBI, to the EPA. The file must be generated using the EPA's ERT 
or an alternate electronic file consistent with the XML schema listed 
on the EPA's ERT website. Submit the file on a compact disc, flash 
drive, or other commonly used electronic storage medium and clearly 
mark the medium as CBI. Mail the electronic medium to U.S. EPA/OAQPS/
CORE CBI Office, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The 
same file with the CBI omitted must be submitted to the EPA via the 
EPA's CDX as described in paragraphs (f)(1)(i) and (ii). All CBI claims 
must be asserted at the time of submission. Furthermore, under CAA 
section 114(c), emissions data is not entitled to confidential 
treatment, and the EPA is required to make emissions data available to 
the public. Thus, emissions data will not be protected as CBI and will 
be made publicly available.
    (2) If you are the owner or operator of an affected engine, you 
shall submit a semi-annual report, at least every six months, in PDF 
format to the EPA via CEDRI or analogous electronic reporting approach 
provided by the EPA to report data required by this section. The report 
shall contain the following information:
    (i) The name and address of the owner and operator;
    (ii) The address of the subject engine;
    (iii) Longitude and latitude coordinates of the subject engine;
    (iv) Identification of the subject engine;
    (v) Statement of compliance with the applicable emission limit 
under Sec.  52.41(b);
    (vi) Statement of compliance regarding the conduct of maintenance 
and operations in a manner consistent with good air pollution control 
practices for minimizing emissions;
    (vii) The date and results of the performance test conducted 
pursuant to Sec.  52.41(d);
    (viii) If applicable, a statement documenting any change in the 
operating characteristics of the subject engine; and
    (ix) A statement certifying that the information included in the 
semi-annual report is complete and accurate.
    (3) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for 
failure to timely comply with that reporting requirement. To assert a 
claim of EPA system outage, you must meet the requirements outlined in 
paragraphs (f)(3)(i) through (vii) of this section.
    (i) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (ii) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (iii) The outage may be planned or unplanned.
    (iv) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (v) You must provide to the Administrator a written description 
identifying:
    (A) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (vi) The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (vii) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (4) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of force majeure for 
failure to timely comply with that reporting requirement. To assert a 
claim of force majeure, you must meet the requirements outlined in 
paragraphs (f)(4)(i) through (v) of this section.
    (i) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the

[[Page 20179]]

affected facility (e.g., large scale power outage).
    (ii) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (iii) You must provide to the Administrator:
    (A) A written description of the force majeure event;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (iv) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (v) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  52.42   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
the Cement and Concrete Product Manufacturing Industry?

    (a) Definitions. All terms not defined herein shall have the 
meaning given them in the Act and in subpart A of part 60.
    Affected unit means a cement kiln meeting the applicability 
criteria of this section.
    Cement plant means any facility manufacturing cement by either the 
wet or dry process.
    Clinker means the product of a cement kiln from which finished 
cement is manufactured by milling and grinding.
    Cement kiln means an installation, including any associated pre-
heater or pre-calciner devices, that produces clinker by heating 
limestone and other materials to produce Portland cement.
    Operating day means a 24-hour period beginning at 12:00 midnight 
during which the kiln produces clinker at any time.
    Rolling average means the weighted average of all data, meeting QA/
QC requirements or otherwise normalized, collected during the 
applicable averaging period. The period of a rolling average stipulates 
the frequency of data averaging and reporting. To demonstrate 
compliance with an operating parameter a 30-day rolling average period 
requires calculation of a new average value each operating day and 
shall include the average of all the hourly averages of the specific 
operating parameter. For demonstration of compliance with an emissions 
limit based on pollutant concentration, a 30-day rolling average is 
comprised of the average of all the hourly average concentrations over 
the previous 30 operating days. For demonstration of compliance with an 
emissions limit based on lbs-pollutant per production unit, the 30-day 
rolling average is calculated by summing the hourly mass emissions over 
the previous 30 operating days, then dividing that sum by the total 
production during the same period.
    (b) Applicability. You are subject to the requirements of this 
section if you own or operate a new or existing cement kiln that emits 
or has the potential to emit 100 tons per year or more of 
NOX and is located within any of the States listed in Sec.  
52.40(a)(1)(ii), including Indian country located within the borders of 
any such State(s).
    (c) Emission limitations (1) If you own or operate a cement kiln 
under paragraph (b) of this section you are subject to the 
NOX emissions limits in the following table and the 
NOX source cap limit under paragraph (c)(2) of this section, 
beginning with the 2026 ozone season and in each ozone season 
thereafter.

                       Table 1 to Paragraph (c)(1)
------------------------------------------------------------------------
                                                           Proposed NOX
                                                             emissions
                        Kiln type                          limit (lb/ton
                                                            of clinker)
 
------------------------------------------------------------------------
Long Wet................................................             4.0
Long Dry................................................             3.0
Preheater...............................................             3.8
Precalciner.............................................             2.3
Preheater/Precalciner...................................             2.8
------------------------------------------------------------------------

    (2) The NOX source cap limit is calculated in accordance 
with the following equation:
[GRAPHIC] [TIFF OMITTED] TP06AP22.004

Where:

CAP2015 Ozone Transport = total allowable NOX emissions 
from all cement kilns located at one cement plant, in tons per day, 
on a 30-operating day rolling average basis;
KD = 1.7 pounds NOX per ton of clinker for dry preheater-
precalciner or precalciner kilns;
KW = 3.4 pounds NOX per ton of clinker for long wet 
kilns;
ND = the average annual production in tons of clinker plus one 
standard deviation for the three most recent calendar years from all 
dry preheater-precalciner or precalciner kilns located at one cement 
plant; and
NW = the average annual production in tons of clinker plus one 
standard deviation for the three most recent calendar years from all 
long wet kilns located at one cement plant.

    (d)Testing and monitoring requirements (1) If you own or operate a 
cement manufacturing plant subject to the NOX emissions 
limits under paragraph (c) of this section you must conduct performance 
tests, on a semi-annual basis, in accordance with the applicable 
reference test methods of 40 CFR part 60, Appendix A, any alternative 
test method approved by EPA as of April 6, 2022 under 40 CFR 59.104(f), 
60.8(b)(3), 61.13(h)(1)(ii), 63.7(e)(2)(ii), or 65.158(a)(2) and 
available at EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods and procedures 
approved by EPA through notice-and-comment rulemaking. You must 
calculate and record the 30-operating day rolling emission rate of 
NOX as the total of all hourly emissions data for a cement 
kiln in the preceding 30 days, divided by the total tons of clinker 
produced in that kiln during the same 30-operating day period using 
Equation 6 of 40 CFR 60.64(c)(1), shown in this equation:

[[Page 20180]]

[GRAPHIC] [TIFF OMITTED] TP06AP22.005

Where:
E30D = 30 kiln operating day average emission rate of 
NOX, in lbs/ton of clinker.
Ci = Concentration of NOX for hour i, in ppm.
Qi = Volumetric flow rate of effluent gas for hour i, where Ci and 
Qi are on the same basis (either wet or dry), in scf/hr.
P = 30 days of clinker production during the same time period as the 
NOX emissions measured, in tons.
k = Conversion factor, 1.194 x 10-7 for NOX, 
in lb/scf/ppm.
n = Number of kiln operating hours over 30 kiln operating days.

    (e) Recordkeeping requirements (1) If you own or operate a cement 
manufacturing plant subject to the NOX emissions limits 
under paragraph (c) of this section you must retain records of the 
calculations and measurements as required in paragraph (d) of this 
section for the 5-year period specified in 52.40(b)(3).
    (2) Any records required to be maintained by this section that are 
submitted electronically via the EPA's CEDRI may be maintained in 
electronic format. This ability to maintain electronic copies does not 
affect the requirement for facilities to make records, data, and 
reports available upon request to the EPA as part of an on-site 
compliance evaluation.
    (f) Reporting requirements (1) Within 60 days after the date of 
completing each performance test required by this section, you must 
submit the results of the performance test following the procedures 
specified in paragraphs (f)(1)(i) through (iii) of this section:
    (i) Data collected using test methods supported by the EPA's ERT as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test. Submit the results of the performance test to the EPA via the 
CEDRI or analogous electronic reporting approach provided by the EPA to 
report data required by this section, which can be accessed through the 
EPA's CDX (https://cdx.epa.gov/). The data must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the XML schema listed on the EPA's ERT 
website.
    (ii) Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test. The results of the performance test must be included as an 
attachment in the ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT website. Submit the ERT 
generated package or alternative file to the EPA via CEDRI.
    (iii) CBI. Do not use CEDRI to submit information you claim as CBI. 
Anything submitted using CEDRI cannot later be claimed CBI. Although we 
do not expect persons to assert a claim of CBI, if you wish to assert a 
CBI claim for some of the information submitted under paragraph 
(f)(1)(i) or (ii) of this section, you must submit a complete file, 
including information claimed to be CBI, to the EPA. The file must be 
generated using the EPA's ERT or an alternate electronic file 
consistent with the XML schema listed on the EPA's ERT website. Submit 
the file on a compact disc, flash drive, or other commonly used 
electronic storage medium and clearly mark the medium as CBI. Mail the 
electronic medium to U.S. EPA/OAQPS/CORE CBI Office, MD C404-02, 4930 
Old Page Rd., Durham, NC 27703. The same file with the CBI omitted must 
be submitted to the EPA via the EPA's CDX as described in paragraphs 
(f)(1)(i) and (ii) of this section. All CBI claims must be asserted at 
the time of submission. Furthermore, under CAA section 114(c), 
emissions data is not entitled to confidential treatment, and the EPA 
is required to make emissions data available to the public. Thus, 
emissions data will not be protected as CBI and will be made publicly 
available.
    (2) If you are the owner or operator of an affected cement kiln, 
you shall submit a semi-annual, at least every six months, report in 
PDF format to the EPA via CEDRI or analogous electronic reporting 
approach provided by the EPA to report data required by this section.
    (3) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for 
failure to timely comply with that reporting requirement. To assert a 
claim of EPA system outage, you must meet the requirements outlined in 
paragraphs (f)(3)(i) through (vii) of this section.
    (i) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (ii) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (iii) The outage may be planned or unplanned.
    (iv) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (v) You must provide to the Administrator a written description 
identifying:
    (A) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (vi) The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (vii) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (4) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of force majeure for 
failure to timely comply with that reporting requirement. To assert a 
claim of force majeure, you must meet the requirements outlined in 
paragraphs (f)(4)(i) through (v) of this section.
    (i) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage).

[[Page 20181]]

    (ii) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (iii) You must provide to the Administrator:
    (A) A written description of the force majeure event;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (iv) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (v) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  52.43   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
the Iron and Steel Mills and Ferroalloy Manufacturing Industry?

    (a) Definitions. All terms not defined herein shall have the 
meaning given them in the Act and in subpart A of part 60.
    Affected unit means any annealing furnace, basic oxygen process 
furnace, blast furnace, coke oven facility, electric arc furnace, ladle 
metallurgy furnace, ladle/tundish preheating system, reheat furnace, 
taconite production kiln, vacuum degasser, and industrial boiler 
meeting the applicability criteria of this section, and any such unit 
contained within a BOF Shop meeting the applicability criteria of this 
section.
    Annealing furnace shall mean a furnace used to heat materials at 
very high temperatures to change their hardness and strength 
properties.
    Basic Oxygen Process Furnace (BOF) shall mean a refractory-lined 
vessel in which high-purity oxygen is blown under pressure through a 
bath of molten iron, scrap metal, and fluxes to produce steel. This 
definition includes both top and bottom blown furnaces, but does not 
include argon oxygen decarburization furnaces.
    Blast furnace means refractory-lined furnaces charged through its 
top with iron ore pellets (taconite), sinter, flux (limestone and 
dolomite), and coke in a reducing atmosphere to produce iron.
    BOF Shop means the place where steel making operations occur, 
beginning with the transfer of molten iron (hot metal) from the torpedo 
car and ending just prior to casting the molten steel, including hot 
metal transfer, desulfurization, slag skimming, refining in a basic 
oxygen process furnace, and ladle metallurgy.
    BOF Baghouse System means the control system for control of 
emissions from charging and tapping of the BOFs, including the capture 
hoods, ductwork and the BOF Baghouse.
    Coke means carbon product that is formed by the thermal 
distillation of coal at high temperatures in the absence of air in coke 
oven batteries.
    Coke Ovens means ovens producing coke for use in blast furnaces.
    Day means a calendar day unless expressly stated to be a business 
day. In computing any period of time for recordkeeping and reporting 
purposes where the last day would fall on a Saturday, Sunday, or 
Federal holiday, the period shall run until the close of business of 
the next business day.
    Electric Arc Furnace means a furnace equipped with electrodes used 
to produce carbon steels and alloy steels primarily by recycling 
ferrous scrap.
    Exceedance means a reading in excess of an applicable opacity or 
emissions limitation.
    Ladle Metallurgy Furnace means a furnace used to refine molten 
steel into specialty grades while keeping the steel in the ladle.
    Ladle/Tundish Preheaters means equipment used to preheat ladles or 
tundishes to minimize temperature drop prior to use in iron or molten 
steel refinement.
    Reheat Furnace means a furnace used to heat steel product to 
temperatures at which it will be suitable for deformation and further 
processing.
    Steel Production Cycle means the operations conducted within the 
basic oxygen process furnace shop that are required to produce each 
batch of steel, including scrap charging, preheating, hot metal 
charging, primary oxygen blowing, sampling, (vessel turndown and 
turnup), additional oxygen blowing, tapping, and deslagging. The steel 
production cycle begins when the scrap is charged to the furnace and 
ends three minutes after the slag is emptied from the vessel into the 
slag pot.
    Taconite production kiln means a furnace designed to dry and 
indurate taconite concentrates to create taconite pellets.
    Vacuum degasser means a unit operated within an iron and steel 
facility to expose molten steel at low pressure to remove certain gases 
during steel refinement.
    (b) Applicability The requirements of this section apply to each 
new or existing emissions unit at an iron and steel mill or ferroalloy 
manufacturing facility that directly emits or has the potential to emit 
100 tons per year or more of NOX, and to each BOF Shop 
containing two or more such units that collectively emit or have the 
potential to emit 100 tons per year or more of NOX, and that 
is located within any of the States listed in Sec.  52.40(a)(1)(ii), 
including Indian country located within the borders of any such 
State(s).
    (c) Emissions Limitations and Requirements. Beginning with the 2026 
ozone season and in each ozone season thereafter, the emissions 
limitations in the following table must be met on a 3-hour rolling 
average.

                        Table 1 to Paragraph (c)
------------------------------------------------------------------------
                                            NOX Emissions standard or
             Emission unit                     control requirement
------------------------------------------------------------------------
Blast Furnace..........................  0.03 lb/mmBtu.
Basic Oxygen Process Furnace...........  0.07 lb/ton steel.
Electric Arc Furnace...................  0.15 lb/ton steel.
Ladle/tundish Preheaters...............  0.06 lb/mmBtu.
Reheat furnace.........................  0.05 lb/mmBtu.
Annealing Furnace......................  0.06 lb/mmBtu.
Vacuum Degasser........................  0.03 lb/mmBtu.
Ladle Metallurgy Furnace...............  0.1 lb/ton steel.
Taconite Production Kilns..............  Install and operate low NOX
                                          burners as required by 2013
                                          and 2016 Minnesota FIPs. 40
                                          CFR Sec.   52.1183.
Coke Ovens (charging)..................  0.15 lb/ton of coal charged.
Coke Oven push cars and pushing-         0.015 lb/ton of coal pushed.
 charging machines (pushing).

[[Page 20182]]

 
Boilers--Coal, blast furnace gas, and    0.20 lb/mmBtu.
 coke oven gas.
Boilers--Residual oil..................  0.20 lb/mmBtu.
Boilers--Distillate oil................  0.12 lb/mmBtu.
Boilers--Natural gas...................  0.08 lb/mmBtu.
------------------------------------------------------------------------

    (d) Compliance and Monitoring Requirements--(1) Compliance 
Requirements (i) Each affected unit identified in Table 1 to paragraph 
(c) of this section must design, install, maintain, and continuously 
operate NOX control devices as necessary to achieve 
emissions limits set forth in Table 1 to paragraph (c) of this section 
in a manner consistent with good air pollution control practices as 
described in 40 CFR 63.6(e).
    (A) If you are the owner or operator of an affected unit not 
identified in paragraph (d)(1)(i)(B) of this section, you must submit 
to EPA a work plan for each affected unit within 180 days of the 
effective date of this rule identifying how each affected unit will 
comply with the emissions limits set forth in Table 1 to paragraph (c) 
of this section. Each work plan must include identification of the 
control device selected and the phased construction timeframe by which 
you will design, install, and consistently operate the device.
    (B) For each taconite production kiln affected by this rule, you 
must install, maintain, and continuously operate low-NOX 
burners to reduce existing average NOX emissions from the 
facility by 40% during all periods of kiln operation.
    (1) If you have already installed low-NOX burners as 
required by the 2013 or 2016 Minnesota Regional Haze Federal 
Implementation Plans,\352\ then you must submit a report to EPA within 
180 days of the effective date of this rule demonstrating that the low-
NOX burner is designed to achieve 40% reduction of kiln 
NOX emissions.
---------------------------------------------------------------------------

    \352\ https://archive.epa.gov/reg5oair/taconite/web/html/index.html.
---------------------------------------------------------------------------

    (2) If you have not yet installed low-NOX burners as 
required by the 2013 or 2016 Minnesota Regional Haze Federal 
Implementation Plans, then you must submit a work plan identifying the 
low-NOX burner selected and the phased construction 
timeframe by which you will design, install, and consistently operate 
the burner. Each work plan shall include performance test results 
obtained within five years of the effective date of this rule to be 
used as baseline emission testing data providing the basis for required 
emission reductions.
    (2) Monitoring Requirements (i) For each unit identified in Table 1 
to paragraph (c) of this section of this rule, you must install, 
operate, and maintain a NOX continuous emission monitoring 
system (CEMS) to monitor compliance with the emissions limits set forth 
in Table 1 to paragraph (c) of this section. Each CEMS shall be 
installed and operated in accordance with requirements set forth at 40 
CFR part 60, appendix B.
    (ii) You must conduct a performance evaluation of each CEMS 
according to the requirements in 40 CFR 63.8 and according to 40 CFR 
part 60, appendix B.
    (iii) You must notify EPA in writing of your intention to conduct a 
performance test at least 60 calendar days before the performance test 
is initially scheduled to begin in accordance with 40 CFR 63.7 (b).
    (iv) As specified in 40 CFR 63.8(c)(4)(ii), each CEMS must complete 
a minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period. You must have at least 
two data points, each representing a different 15-minute period within 
the same hour, to have a valid hour of data.
    (v) All CEMS data must be reduced as specified in 40 CFR 63.8(g)(2) 
and recorded as NOX in parts per million by volume, dry 
basis (ppmvd).
    (vi) Proper maintenance. You must maintain the CEMS equipment at 
all times that the unit is operating, including but not limited to, 
maintaining necessary parts for routine repairs of the monitoring 
equipment.
    (vii) You must conduct all monitoring in continuous operation at 
all times that the unit is operating, except for, as applicable, 
monitoring malfunctions, associated repairs, and required quality 
assurance or control activities (including, as applicable, calibration 
drift checks and required zero and high-level adjustments). Quality 
assurance or control activities must be performed according to 
procedure 1 of 40 CFR part 60, appendix F.
    (viii) Data recorded during monitoring malfunctions, associated 
repairs, out-of-control periods, and required quality assurance or 
control activities should not be used for purposes of calculating data 
averages. You must use all of the data collected from all other periods 
in assessing compliance. A monitoring malfunction is any sudden, 
infrequent, not reasonably preventable failure of the monitoring 
equipment to provide valid data. Monitoring failures that are caused in 
part by poor maintenance or careless operation are not malfunctions. 
Any period for which the monitoring system is out-of-control and data 
are not available for required calculations constitutes a deviation 
from the monitoring requirements.
    (e) Recordkeeping requirements (1) You shall maintain records of 
the following information for each day the affected unit operates:
    (i) Calendar date;
    (ii) The average hourly NOX emission rates measured or 
predicted;
    (iii) The 30-day average NOX emission rates calculated 
at the end of each affected unit operating day from the measured or 
predicted hourly NOX emission rates for the preceding 30 
steam generating unit operating days;
    (iv) Identification of the affected unit operating days when the 
calculated 30-day average NOX emission rates are in excess 
of the applicable NOX emission limit in Table 1 to paragraph 
(c) of this section with the reasons for such excess emissions as well 
as a description of corrective actions taken;
    (v) Identification of the affected unit operating days for which 
pollutant data have not been obtained, including reasons for not 
obtaining sufficient data and a description of corrective actions 
taken;
    (vi) Identification of the times when emission data have been 
excluded from the calculation of average emission rates and the reasons 
for excluding data;
    (viii) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (ix) Description of any modifications to the CEMS that could affect 
the ability of the CEMS to comply with Performance Specification 2 or 3 
in appendix B of 40 CFR part 60; and
    (x) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F.

[[Page 20183]]

    (2) Any records required to be maintained by this section that are 
submitted electronically via the EPA's CEDRI may be maintained in 
electronic format. This ability to maintain electronic copies does not 
affect the requirement for facilities to make records, data, and 
reports available upon request to the EPA as part of an on-site 
compliance evaluation.
    (f) Reporting requirements (1) Within 180 days of the effective 
date of this rule, you shall submit a work plan in accordance with 
requirements set forth in paragraph (d)(1)(i)(A) of this section, 
including identification of the control device selected and the phased 
construction timeframe by which you will design, install, and 
consistently operate the device. For taconite kilns subject to 
paragraph (d)(1)(i)(B)(2) of this section each work plan shall include 
performance test results obtained within five years of the effective 
date of this rule to be used as baseline emission testing data 
providing the basis for required emission reductions.
    (2) By no later than March 30, 2026, each owner/operator of an 
affected unit shall submit a final report certifying installation of 
each selected control device has completed. Each such report shall 
contain dates of final construction and relevant performance testing, 
where applicable, demonstrating compliance with limits set forth in 
Table 1 to paragraph (c) of this section.
    (3) Within 60 days after the date of completing each performance 
test required by this section, you must submit the results of the 
performance test or performance evaluation of the CEMS following the 
procedures specified in paragraphs (c)(3)(i) through (iii) of this 
section:
    (i) Data collected using test methods supported by the EPA's ERT as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test. Submit the results of the performance test to the EPA via the 
CEDRI or analogous electronic reporting approach provided by the EPA to 
report data required by this section, which can be accessed through the 
EPA's CDX (https://cdx.epa.gov/). The data must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the XML schema listed on the EPA's ERT 
website.
    (ii) Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test. The results of the performance test must be included as an 
attachment in the ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT website. Submit the ERT 
generated package or alternative file to the EPA via CEDRI.
    (iii) CBI. Do not use CEDRI to submit information you claim as CBI. 
Anything submitted using CEDRI cannot later be claimed CBI. Although we 
do not expect persons to assert a claim of CBI, if you wish to assert a 
CBI claim for some of the information submitted under paragraph 
(f)(1)(i) or (ii) of this section, you must submit a complete file, 
including information claimed to be CBI, to the EPA. The file must be 
generated using the EPA's ERT or an alternate electronic file 
consistent with the XML schema listed on the EPA's ERT website. Submit 
the file on a compact disc, flash drive, or other commonly used 
electronic storage medium and clearly mark the medium as CBI. Mail the 
electronic medium to U.S. EPA/OAQPS/CORE CBI Office, MD C404-02, 4930 
Old Page Rd., Durham, NC 27703. The same file with the CBI omitted must 
be submitted to the EPA via the EPA's CDX as described in paragraphs 
(f)(1)(i) and (ii). All CBI claims must be asserted at the time of 
submission. Furthermore, under CAA section 114(c), emissions data is 
not entitled to confidential treatment, and the EPA is required to make 
emissions data available to the public. Thus, emissions data will not 
be protected as CBI and will be made publicly available.
    (4) You are required to submit excess emission reports for any 
excess emissions that occurred during the reporting period. Excess 
emissions are defined as any calculated 30-day rolling average 
NOX emission rate, as determined under paragraph (c)(3)(iii) 
of this section, that exceeds the applicable emission limit in 
paragraph (c) of this section. Excess emission reports must be 
submitted in PDF format to the EPA via CEDRI or analogous electronic 
reporting approach provided by the EPA to report data required by this 
section.
    (5) If you own or operate an affected unit subject to the 
continuous monitoring requirements for NOX under paragraph 
(d) of this section, you shall submit reports containing the 
information recorded under paragraph (d) as described in paragraph 
(e)(6) of this section. Compliance reports for continuous monitoring 
must be submitted in PDF format to the EPA via CEDRI or analogous 
electronic reporting approach provided by the EPA to report data 
required by this section.
    (6) If you own or operate an affected unit, you must submit 
electronic quarterly reports no later than 30 days after the end of the 
calendar quarter. The reports shall be accompanied by a certification 
from the owner or operator indicating whether the affected unit was in 
compliance with the applicable emission limits and minimum data 
requirements of this section during the reporting period. These 
quarterly reports must be submitted in PDF format to the EPA via CEDRI 
or analogous electronic reporting approach provided by the EPA to 
report data required by this section.
    (7) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for 
failure to timely comply with that reporting requirement. To assert a 
claim of EPA system outage, you must meet the requirements outlined in 
paragraphs (f)(7)(i) through (vii) of this section.
    (i) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (ii) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (iii) The outage may be planned or unplanned.
    (iv) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (v) You must provide to the Administrator a written description 
identifying:
    (A) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (vi) The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (vii) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (8) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of force majeure for 
failure to timely comply with that

[[Page 20184]]

reporting requirement. To assert a claim of force majeure, you must 
meet the requirements outlined in paragraphs (f)(8)(i) through (v) of 
this section.
    (i) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage).
    (ii) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (iii) You must provide to the Administrator:
    (A) A written description of the force majeure event;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (iv) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (v) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  52.44   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
the Glass and Glass Product Manufacturing Industry?

    (a) Definitions. All terms not defined herein shall have the 
meaning given them in the Act and in subpart A of part 60.
    Affected units means a glass manufacturing furnace meeting the 
applicability criteria of this section.
    All-electric melter means a glass melting furnace in which all the 
heat required for melting is provided by electric current from 
electrodes submerged in the molten glass, although some fossil fuel may 
be charged to the furnace as raw material only.
    Borosilicate recipe means glass product composition of the 
following approximate ranges of weight proportions: 60 to 80 percent 
silicon dioxide, 4 to 10 percent total R2O (e.g., 
Na2O and K2O), 5 to 35 percent boric oxides, and 
0 to 13 percent other oxides.
    Container glass means glass made of soda-lime recipe, clear or 
colored, which is pressed and/or blown into bottles, jars, ampoules, 
and other products listed in Standard Industrial Classification 3221 
(SIC 3221).
    Experimental furnace means a glass melting furnace with the sole 
purpose of operating to evaluate glass melting processes, technologies, 
or glass products. An experimental furnace does not produce glass that 
is sold (except for further research and development purposes) or that 
is used as a raw material for nonexperimental furnaces.
    Flat glass means glass made of soda-lime recipe and produced into 
continuous flat sheets and other products listed in SIC 3211.
    Glass melting furnace means a unit comprising a refractory vessel 
in which raw materials are charged, melted at high temperature, 
refined, and conditioned to produce molten glass. The unit includes 
foundations, superstructure and retaining walls, raw material charger 
systems, heat exchangers, melter cooling system, exhaust system, 
refractory brick work, fuel supply and electrical boosting equipment, 
integral control systems and instrumentation, and appendages for 
conditioning and distributing molten glass to forming apparatuses. The 
forming apparatuses, including the float bath used in flat glass 
manufacturing and flow channels in wool fiberglass and textile 
fiberglass manufacturing, are not considered part of the glass melting 
furnace.
    Glass produced means the weight of the glass pulled from the glass 
melting furnace.
    Hand glass melting furnace means a glass melting furnace where the 
molten glass is removed from the furnace by a glassworker using a 
blowpipe or a pontil.
    Lead recipe means glass product composition of the following ranges 
of weight proportions: 50 to 60 percent silicon dioxide, 18 to 35 
percent lead oxides, 5 to 20 percent total R2O (e.g., 
Na2O and K2O), 0 to 8 percent total 
R2O3 (e.g., Al2O3), 0 to 15 
percent total RO (e.g., CaO, MgO), other than lead oxide, and 5 to 10 
percent other oxides.
    Pressed and blown glass means glass which is pressed, blown, or 
both, including textile fiberglass, noncontinuous flat glass, 
noncontainer glass, and other products listed in SIC 3229. It is 
separated into: Glass of borosilicate recipe, Glass of soda-lime and 
lead recipes, and Glass of opal, fluoride, and other recipes.
    Raw material means minerals, such as silica sand, limestone, and 
dolomite; inorganic chemical compounds, such as soda ash (sodium 
carbonate), salt cake (sodium sulfate), and potash (potassium 
carbonate); metal oxides and other metal-based compounds, such as lead 
oxide, chromium oxide, and sodium antimonate; metal ores, such as 
chromite and pyrolusite; and other substances that are intentionally 
added to a glass manufacturing batch and melted in a glass melting 
furnace to produce glass. Metals that are naturally-occurring trace 
constituents or contaminants of other substances are not considered to 
be raw materials.
    Rebricking means cold replacement of damaged or worn refractory 
parts of the glass melting furnace. Rebricking includes replacement of 
the refractories comprising the bottom, sidewalls, or roof of the 
melting vessel; replacement of refractory work in the heat exchanger; 
replacement of refractory portions of the glass conditioning and 
distribution system.
    Soda-lime recipe means glass product composition of the following 
ranges of weight proportions: 60 to 75 percent silicon dioxide, 10 to 
17 percent total R2O (e.g., Na2O and 
K2O), 8 to 20 percent total RO but not to include any PbO 
(e.g., CaO, and MgO), 0 to 8 percent total R2O3 
(e.g., Al2O3), and 1 to 5 percent other oxides.
    Textile fiberglass means fibrous glass in the form of continuous 
strands having uniform thickness.
    Wool fiberglass means fibrous glass of random texture, including 
fiber glass insulation, and other products listed in SIC 3296.
    (b) Applicability You are subject to the requirements under this 
section if you own or operate a new or existing glass manufacturing 
furnace that directly emits or has the potential to emit 100 tons per 
year or more of NOX and is located within any of the States 
listed in Sec.  52.40(a)(1)(ii), including Indian country located 
within the borders of any such State(s).
    (c) Emissions limitations If you own or operate an affected unit 
you are subject to the NOX emissions limits in the following 
table beginning with the 2026 ozone season and in each ozone season 
thereafter:

[[Page 20185]]



                        Table 1 to Paragraph (c)
------------------------------------------------------------------------
                                                           Proposed NOX
                                                             emissions
                                                           limit (lb/ton
                      Furnace type                           of glass
                                                             produced)
 
------------------------------------------------------------------------
Container Glass Manufacturing Furnace...................             4.0
Pressed/Blown Glass Manufacturing Furnace or Fiberglass              4.0
 Manufacturing Furnace..................................
Flat Glass Manufacturing Furnace........................             9.2
------------------------------------------------------------------------

    (d) Testing and Monitoring Requirements If you own or operate an 
affected unit you must conduct performance tests, on a semiannual 
basis, in accordance with the applicable reference test methods of 40 
CFR part 60, Appendix A, any alternative test method approved by EPA as 
of April 6, 2022 under 40 CFR 59.104(f), 60.8(b)(3), 61.13(h)(1)(ii), 
63.7(e)(2)(ii), or 65.158(a)(2) and available at EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), 
or other methods and procedures approved by EPA through notice-and-
comment rulemaking. Direct measurement or material balance using good 
engineering practice shall be used to determine the amount of glass 
pulled during the performance test. The rate of glass produced is 
defined as the weight of glass pulled from the affected facility during 
the performance test divided by the number of hours taken to perform 
the performance test.
    (1) Owners or operators of affected units must calculate and record 
the 30-operating day rolling emission rate of NOX as the 
total of all hourly emissions data for a glass manufacturing furnace in 
the preceding 30 days, divided by the total tons of glass produced in 
that furnace during the same 30-operating day period. If a continuous 
emission monitoring system has not been installed on the affected unit, 
the owner or operator shall conduct the following steps:
    (A) Step 1: determine the average pounds of NOX emitted 
per hour by averaging three one-hour tests,
    (B) Step 2: determine the average tons of glass removed per hour 
during the same time period as the three one-hour tests in step 1,
    (C) Step 3: divide the average pounds of NOX emitted per 
hour determined in step 1 by the average tons of glass removed per hour 
determined in step 2,
    (D) Step 4: compare the quotient to the emission limits specified 
at Sec.  52.44(c)(1).
    (2) If a continuous emission monitoring system has been installed 
on the affected unit, on a daily basis the owner or operator shall 
conduct the following steps:
    (A) Step 1: determine the average pounds of NOX emitted 
per day,
    (B) Step 2: determine the tons of glass removed per day,
    (C) Step 3: divide the average pounds of NOX emitted per 
day determined in step (1) by the tons of glass removed per day 
determined in step (2). The quotient is pounds of NOX 
emitted per ton of glass removed; and
    (D) Step 4: compare the quotient to the emission limit specified at 
Sec.  52.44(c)(1).
    (e) Recordkeeping requirements (1) If you own or operate an 
affected unit, you must retain records of the calculations and 
measurements as required in paragraph (e) of this section for 5-year 
period specified in 52.40(b)(3). You must record the results of each 
inspection and maintenance proposed rule in a logbook (written or 
electronic format). You shall keep the logbook onsite and make the 
logbook available to the permitting authority upon request, consistent 
with the requirements of 40 CFR part 63, subpart SSSSSS, Sec.  
63.11457(c).
    (2) Any records required to be maintained by this section that are 
submitted electronically via the EPA's CEDRI may be maintained in 
electronic format. This ability to maintain electronic copies does not 
affect the requirement for facilities to make records, data, and 
reports available upon request to the EPA as part of an on-site 
compliance evaluation.
    (f) Reporting requirements (1) Within 60 days after the date of 
completing each performance test required by this section, you must 
submit the results of the performance test following the procedures 
specified in paragraphs (e)(1)(i) through (iii) of this section:
    (i) Data collected using test methods supported by the EPA's ERT as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test. Submit the results of the performance test to the EPA via the 
CEDRI or analogous electronic reporting approach provided by the EPA to 
report data required by this section, which can be accessed through the 
EPA's CDX (https://cdx.epa.gov/). The data must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the XML schema listed on the EPA's ERT 
website.
    (ii) Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test. The results of the performance test must be included as an 
attachment in the ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT website. Submit the ERT 
generated package or alternative file to the EPA via CEDRI.
    (iii) CBI. Do not use CEDRI to submit information you claim as CBI. 
Anything submitted using CEDRI cannot later be claimed CBI. Although we 
do not expect persons to assert a claim of CBI, if you wish to assert a 
CBI claim for some of the information submitted under paragraph 
(f)(1)(i) or (ii) of this section, you must submit a complete file, 
including information claimed to be CBI, to the EPA. The file must be 
generated using the EPA's ERT or an alternate electronic file 
consistent with the XML schema listed on the EPA's ERT website. Submit 
the file on a compact disc, flash drive, or other commonly used 
electronic storage medium and clearly mark the medium as CBI. Mail the 
electronic medium to U.S. EPA/OAQPS/CORE CBI Office, MD C404-02, 4930 
Old Page Rd., Durham, NC 27703. The same file with the CBI omitted must 
be submitted to the EPA via the EPA's CDX as described in paragraphs 
(f)(1)(i) and (ii). All CBI claims must be asserted at the time of 
submission. Furthermore, under CAA section 114(c), emissions data is 
not entitled to confidential treatment, and the EPA is required to make 
emissions data available to the public. Thus, emissions data will not 
be protected as CBI and will be made publicly available.
    (2) If you own or operate an affected unit, you shall submit a 
semi-annual report, at least every six months, in PDF format to the EPA 
via CEDRI or analogous electronic reporting approach provided by the 
EPA to report data required by this section.
    (3) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for 
failure to timely comply with that reporting requirement. To assert a 
claim of EPA system outage, you must meet the requirements outlined in 
paragraphs (f)(3)(i) through (vii) of this section.
    (i) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (ii) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.

[[Page 20186]]

    (iii) The outage may be planned or unplanned.
    (iv) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (v) You must provide to the Administrator a written description 
identifying:
    (A) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (vi) The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (vii) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (4) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of force majeure for 
failure to timely comply with that reporting requirement. To assert a 
claim of force majeure, you must meet the requirements outlined in 
paragraphs (f)(4)(i) through (v) of this section.
    (i) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage).
    (ii) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (iii) You must provide to the Administrator:
    (A) A written description of the force majeure event;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (iv) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (v) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.


Sec.  52.45   What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
the Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills Industries?

    (a) Definitions. All terms not defined herein shall have the 
meaning given them in the Act and in subpart A of 40 CFR part 60.
    Affected unit means an industrial boiler meeting the applicability 
criteria of this section.
    (b) Applicability. (1) The requirements of this section apply to 
each new or existing boiler with a design capacity of 100 mmBtu/hr or 
greater fueled by coal, residual oil, distillate oil, or natural gas, 
located at sources that are within the Basic Chemical Manufacturing 
industry (NAICS code 3251xx), the Petroleum and Coal Products 
Manufacturing industry (NAICS code 3241xx), and the Pulp, Paper, and 
Paperboard industry (NAICS code 3221xx), and which is located within 
any of the States listed in Sec.  52.40(a)(1)(ii), including Indian 
country located within the borders of any such State(s).
    (c) Emission limitations. Beginning with the 2026 ozone season and 
in each ozone season thereafter, the following emission limits apply, 
based on a 30-day averaging time:
    (1) Coal-fired industrial boilers: 0.20 lbs NOX/mmBtu;
    (2) Residual oil-fired industrial boilers: 0.15 lbs NOX/
mmBtu;
    (3) Distillate oil-fired industrial boilers: 0.12 lbs 
NOX/mmBtu; and
    (4) Natural gas-fired industrial boilers: 0.08 lbs NOX/
mmBtu.
    (d) Initial compliance testing. (1) To determine compliance with 
the emission limits for NOX identified in paragraph (c) of 
this section, you shall conduct an initial compliance test as described 
in 40 CFR Sec.  60.8 using the continuous system for monitoring 
NOX specified by EPA Test Method 7E--Determination of 
Nitrogen Oxide Emissions from Stationary Sources (Instrumental Analyzer 
Procedure), as described at 40 CFR part 60, Appendix A-4. In lieu of 
the timing of the compliance test described in 40 CFR 60.8(a), the test 
shall be conducted within 90 days from the installation of the 
pollution control equipment used to comply with the NOX 
emission limits in paragraph (c) of this section.
    (2) For the initial compliance test, NOX emissions from 
the affected unit shall be monitored for 30 successive operating days 
and the 30-day average emission rate will be used to determine 
compliance with the NOX emission limits in paragraph (c) of 
this section. The 30-day average emission rate is calculated as the 
average of all hourly emission data recorded by the monitoring system 
during the 30-day test period.
    (e) Monitoring requirements. (1) The NOX emission limits 
in paragraph (c) of this section shall apply at all times.
    (2) You shall install, calibrate, maintain, and operate a 
continuous emissions monitoring system (CEMS) for measuring 
NOX emissions and either oxygen (O2) or carbon 
dioxide (CO2), unless the Administrator has approved a 
request from the you to use an alternative monitoring technique under 
paragraph (e)(8) of this section. If you have previously installed a 
NOX emission rate CEMS to meet the requirements of 40 CFR 
part 75 and continue to meet the ongoing requirements of 40 CFR part 
75, that CEMS may be used to meet the monitoring requirements of this 
section.
    (3) The CEMS required under paragraph (e)(2) of this section shall 
be operated and data recorded during all periods of operation of the 
affected unit except for CEMS breakdowns and repairs. Data shall be 
recorded during calibration checks and zero and span adjustments.
    (4) The 1-hour average NOX emission rates measured by 
the CEMS required by paragraph (e)(2) of this section shall be 
expressed in terms of lbs/mmBtu heat input and shall be used to 
calculate the average emission rates under 40 CFR 52.45(c).
    (5) Following the date on which the initial compliance test is 
completed, you shall determine compliance with the applicable 
NOX emission limit in paragraph (c) of this section on a 
continuous basis using a 30-day rolling

[[Page 20187]]

average emission rate unless the affected unit monitors emissions by 
means of an alternative monitoring procedure approved pursuant to 
paragraph (e)(8) of this section. A new 30-day rolling average emission 
rate is calculated for each operating day as the average of all the 
hourly NOX emission data for the preceding 30 operating 
days.
    (6) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems. Additionally, the span value for units combusting coal shall 
be 1,000 ppm NOX, and for units combusting oil or gas the 
span value shall be 500 ppm NOX. As an alternative to 
meeting the span value requirements stated above, you may elect to use 
the NOX span values determined according to section 2.1.2 in 
appendix A to 40 CFR part 75.
    (7) When NOX emission data are not obtained because of 
CEMS breakdowns, repairs, calibration checks and zero and span 
adjustments, emission data will be obtained by using standby monitoring 
systems, Method 7 of 40 CFR part 60, Method 7A of 40 CFR part 60, or 
other approved reference methods to provide emission data for a minimum 
of 75 percent of the operating hours in each affected unit operating 
day, in at least 22 out of 30 successive operating days.
    (8) Installation of a CEMS for NOX may be delayed until 
after the initial performance test has been conducted. If you 
demonstrate during the performance test that emissions of 
NOX are less than 70 percent of the applicable emission 
limit in paragraph (c) of this section, a CEMS for measuring 
NOX emissions is not required. If you demonstrate its boiler 
emits less than 70 percent of the applicable emission limit chooses to 
not install a CEMS, you must submit a written request to the 
Administrator that documents the results of the initial performance 
test and includes an alternative monitoring procedure that will be used 
to track compliance with the applicable NOX emission 
limit(s) in paragraph (c) of this section. The Administrator will 
consider the request and, following public notice and comment, may 
approve the alternative monitoring procedure with or without revision, 
or disapprove the request. Upon receipt of a disapproved request, you 
will have one year to install a CEMS in accordance with the provisions 
for CEMS described in paragraph (e) of this section.
    (f) Recordkeeping requirements (1) You shall record and maintain 
records of the amounts of each fuel combusted during each calendar 
month.
    (2) You shall maintain records of the following information for 
each day the affected unit operates:
    (i) Calendar date;
    (ii) The average hourly NOX emission rates (expressed as 
lbs NO2/mmBtu heat input) measured or predicted;
    (iii) The 30-day average NOX emission rates calculated 
at the end of each affected unit operating day from the measured or 
predicted hourly NOX emission rates for the preceding 30 
steam generating unit operating days;
    (iv) Identification of the affected unit operating days when the 
calculated 30-day average NOX emission rates are in excess 
of the applicable NOX emission limit in paragraph (c) of 
this section with the reasons for such excess emissions as well as a 
description of corrective actions taken;
    (v) Identification of the affected unit operating days for which 
pollutant data have not been obtained, including reasons for not 
obtaining sufficient data and a description of corrective actions 
taken;
    (vi) Identification of the times when emission data have been 
excluded from the calculation of average emission rates and the reasons 
for excluding data;
    (vii) Identification of ``F'' factor used for calculations, method 
of determination, and type of fuel combusted;
    (viii) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (ix) Description of any modifications to the CEMS that could affect 
the ability of the CEMS to comply with Performance Specification 2 or 3 
in appendix B of 40 CFR part 60; and
    (x) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F.
    (3) Any records required to be maintained by this section that are 
submitted electronically via the EPA's CEDRI may be maintained in 
electronic format. This ability to maintain electronic copies does not 
affect the requirement for facilities to make records, data, and 
reports available upon request to the EPA as part of an on-site 
compliance evaluation.
    (g) Reporting requirements. (1) Within 60 days after the date of 
completing each performance test required by this section, you must 
submit the results of the performance test or performance evaluation of 
the CEMS following the procedures specified in paragraphs (g)(i) 
through (iii) of this section:
    (i) Data collected using test methods supported by the EPA's ERT as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test. Submit the results of the performance test to the EPA via the 
CEDRI or analogous electronic reporting approach provided by the EPA to 
report data required by this section, which can be accessed through the 
EPA's CDX (https://cdx.epa.gov/). The data must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the XML schema listed on the EPA's ERT 
website.
    (ii) Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test. The results of the performance test must be included as an 
attachment in the ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT website. Submit the ERT 
generated package or alternative file to the EPA via CEDRI.
    (iii) CBI. Do not use CEDRI to submit information you claim as CBI. 
Anything submitted using CEDRI cannot later be claimed CBI. Although we 
do not expect persons to assert a claim of CBI, if you wish to assert a 
CBI claim for some of the information submitted under paragraph 
(g)(1)(i) or (ii) of this section, you must submit a complete file, 
including information claimed to be CBI, to the EPA. The file must be 
generated using the EPA's ERT or an alternate electronic file 
consistent with the XML schema listed on the EPA's ERT website. Submit 
the file on a compact disc, flash drive, or other commonly used 
electronic storage medium and clearly mark the medium as CBI. Mail the 
electronic medium to U.S. EPA/OAQPS/CORE CBI Office, MD C404-02, 4930 
Old Page Rd., Durham, NC 27703. The same file with the CBI omitted must 
be submitted to the EPA via the EPA's CDX as described in paragraphs 
(g)(1)(i) and (ii) of this section. All CBI claims must be asserted at 
the time of submission. Furthermore, under CAA section 114(c), 
emissions data is not entitled to confidential treatment, and the EPA 
is required to make emissions data available to the public. Thus, 
emissions data will not be protected as CBI and will be made publicly 
available.
    (2) You are required to submit excess emission reports for any 
excess emissions that occurred during the reporting period. Excess 
emissions are defined as any calculated 30-day rolling average 
NOX emission rate, as determined under paragraph (g)(3)(iii) 
of this section, that exceeds the applicable emission limit in 
paragraph (c) of this section. Excess emission reports must be

[[Page 20188]]

submitted in PDF format to the EPA via CEDRI or analogous electronic 
reporting approach provided by the EPA to report data required by this 
section.
    (3) If you own or operate an affected unit subject to the 
continuous monitoring requirements for NOX under paragraph 
(e) of this section, you shall submit reports containing the 
information recorded under paragraph (e) of this section as described 
in paragraph (g)(2) of this section. Compliance reports for continuous 
monitoring must be submitted in PDF format to the EPA via CEDRI or 
analogous electronic reporting approach provided by the EPA to report 
data required by this section.
    (4) If you own or operate an affected unit, you must submit 
electronic quarterly reports no later than 30 days after the end of the 
calendar quarter. The reports shall be accompanied by a certification 
from the owner or operator indicating whether the affected unit was in 
compliance with the applicable emission limits and minimum data 
requirements of this section during the reporting period. These 
quarterly reports must be submitted in PDF format to the EPA via CEDRI 
or analogous electronic reporting approach provided by the EPA to 
report data required by this section.
    (5) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for 
failure to timely comply with that reporting requirement. To assert a 
claim of EPA system outage, you must meet the requirements outlined in 
paragraphs (g)(5)(i) through (vii) of this section.
    (i) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (ii) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (iii) The outage may be planned or unplanned.
    (iv) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (v) You must provide to the Administrator a written description 
identifying:
    (A) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (vi) The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (vii) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (6) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, you may assert a claim of force majeure for 
failure to timely comply with that reporting requirement. To assert a 
claim of force majeure, you must meet the requirements outlined in 
paragraphs (g)(6)(i) through (v) of this section.
    (i) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage).
    (ii) You must submit notification to the Administrator in writing 
as soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (iii) You must provide to the Administrator:
    (A) A written description of the force majeure event;
    (B) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (C) A description of measures taken or to be taken to minimize the 
delay in reporting; and
    (D) The date by which you propose to report, or if you have already 
met the reporting requirement at the time of the notification, the date 
you reported.
    (iv) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (v) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.

Subpart B--Alabama

0
5. Amend Sec.  52.54 by revising paragraphs (b)(2) and (3) and adding 
paragraphs (b)(4) and (5) to read as follows:


Sec.  52.54   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (b) * * *
    (2) The owner and operator of each source and each unit located in 
the State of Alabama and Indian country within the borders of the State 
and for which requirements are set forth under the CSAPR NOX 
Ozone Season Group 2 Trading Program in subpart EEEEE of part 97 of 
this chapter must comply with such requirements with regard to 
emissions occurring in 2017 through 2022. The obligation to comply with 
such requirements with regard to sources and units in the State and 
areas of Indian country within the borders of the State subject to the 
State's SIP authority will be eliminated by the promulgation of an 
approval by the Administrator of a revision to Alabama's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the CSAPR Federal Implementation Plan (FIP) under Sec.  
52.38(b)(1) and (b)(2)(ii) for those sources and units, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in areas of Indian country within the borders of the 
State not subject to the State's SIP authority will not be eliminated 
by the promulgation of an approval by the Administrator of a revision 
to Alabama's SIP.
    (3) The owner and operator of each source and each unit located in 
the State of Alabama and Indian country within the borders of the State 
and for which requirements are set forth under the CSAPR NOX 
Ozone Season Group 3 Trading Program in subpart GGGGG of part 97 of 
this chapter must comply with such requirements with regard to 
emissions occurring in 2023 and each subsequent year. The obligation to 
comply with such requirements with regard to sources and units in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the

[[Page 20189]]

promulgation of an approval by the Administrator of a revision to 
Alabama's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Alabama's SIP.
    (4) Notwithstanding the provisions of paragraphs (b)(2) and (3) of 
this section, if, at the time of the approval of Alabama's SIP revision 
described in paragraph (b)(2) or (3) of this section, the Administrator 
has already started recording any allocations of CSAPR NOX 
Ozone Season Group 2 allowances or CSAPR NOX Ozone Season 
Group 3 allowances under subpart EEEEE or GGGGG, respectively, of part 
97 of this chapter to units in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
for a control period in any year, the provisions of such subpart 
authorizing the Administrator to complete the allocation and 
recordation of such allowances to such units for each such control 
period shall continue to apply, unless provided otherwise by such 
approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (b)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts of unused CSAPR NOX Ozone Season Group 
2 allowances allocated for control periods before 2023 to different 
amounts of CSAPR NOX Ozone Season Group 3 allowances), and 
the provisions of Sec.  97.811(e) of this chapter (concerning the 
recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all such allowances allocated 
to units in the State and Indian country within the borders of the 
State for control periods after 2022) shall continue to apply.

Subpart E--Arkansas

0
6. Amend Sec.  52.184 by:
0
a. Redesignating paragraphs (a) through (c) as paragraphs (a)(1) 
through (3);
0
b. In newly redesignated paragraph (a)(2), removing ``2017 and each 
subsequent year.'' and adding in its place ``2017 through 2022.'', and 
removing the second sentence;
0
c. Revising newly redesignated paragraph (a)(3); and
0
d. Adding paragraphs (a)(4) and (5) and (b).
    The revision and additions read as follows:


Sec.  52.184   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Arkansas and for which requirements are set forth under 
the CSAPR NOX Ozone Season Group 3 Trading Program in 
subpart GGGGG of part 97 of this chapter must comply with such 
requirements with regard to emissions occurring in 2023 and each 
subsequent year. The obligation to comply with such requirements will 
be eliminated by the promulgation of an approval by the Administrator 
of a revision to Arkansas' State Implementation Plan (SIP) as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan (FIP) under Sec.  52.38(b)(1) and (b)(2)(iii), 
except to the extent the Administrator's approval is partial or 
conditional.
    (4) Notwithstanding the provisions of paragraph (a)(3) of this 
section, if, at the time of the approval of Arkansas' SIP revision 
described in paragraph (a)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State for a control period in any year, the 
provisions of subpart GGGGG of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of CSAPR 
NOX Ozone Season Group 3 allowances to such units for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (a)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts of unused CSAPR NOX Ozone Season Group 
2 allowances allocated for control periods before 2023 to different 
amounts of CSAPR NOX Ozone Season Group 3 allowances), and 
the provisions of Sec.  97.811(e) of this chapter (concerning the 
recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all such allowances allocated 
to units in the State for control periods after 2022) shall continue to 
apply.
    (b) The owner and operator of each source located in the State of 
Arkansas and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart F--California

0
7. Add Sec.  52.284 to read as follows:


Sec.  52.284   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    The owner and operator of each source located in the State of 
California and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart I--Delaware

0
8. Amend Sec.  52.440 by adding paragraph (d) to read as follows:


Sec.  52.440   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (d)(1) The owner and operator of each source and each unit located 
in the State of Delaware and for which requirements are set forth under 
the CSAPR NOX Ozone Season Group 3 Trading Program in 
subpart GGGGG of part 97 of this chapter must comply with such 
requirements with regard to emissions occurring in 2023 and each 
subsequent year. The obligation to comply with such requirements will 
be eliminated by the promulgation of an approval by the Administrator 
of a revision to Delaware's State Implementation Plan (SIP) as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan (FIP) under Sec.  52.38(b)(1) and (b)(2)(iii), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Delaware's SIP

[[Page 20190]]

revision described in paragraph (d)(1) of this section, the 
Administrator has already started recording any allocations of CSAPR 
NOX Ozone Season Group 3 allowances under subpart GGGGG of 
part 97 of this chapter to units in the State for a control period in 
any year, the provisions of subpart GGGGG of part 97 of this chapter 
authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.

Subpart O--Illinois

0
9. Amend Sec.  52.731 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.731   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Illinois and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart P--Indiana

0
10. Amend Sec.  52.789 by:
0
a. In paragraph (b)(2), removing ``(b)(2)(iv), except'' and adding in 
its place ``(b)(2)(ii), except'';
0
b. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
c. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.789   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Indiana and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart S--Kentucky

0
11. Amend Sec.  52.940 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.940   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Kentucky and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart T--Louisiana

0
12. Amend Sec.  52.984 by:
0
a. In paragraph (d)(3), revising the second and third sentences;
0
b. Revising paragraph (d)(4);
0
c. In paragraph (d)(5), adding ``and Indian country within the borders 
of the State'' after ``in the State''; and
0
d. Adding paragraph (e).
    The revision and addition read as follows:


Sec.  52.984   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (d) * * *
    (3) * * * The obligation to comply with such requirements with 
regard to sources and units in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Louisiana's State Implementation Plan 
(SIP) as correcting the SIP's deficiency that is the basis for the 
CSAPR Federal Implementation Plan (FIP) under Sec.  52.38(b)(1) 
and(b)(2)(iii) for those sources and units, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in areas of Indian country within the borders of the State not subject 
to the State's SIP authority will not be eliminated by the promulgation 
of an approval by the Administrator of a revision to Louisiana's SIP.
    (4) Notwithstanding the provisions of paragraph (d)(3) of this 
section, if, at the time of the approval of Louisiana's SIP revision 
described in paragraph (d)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
* * * * *
    (e) The owner and operator of each source located in the State of 
Louisiana and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart V--Maryland

0
13. Amend Sec.  52.1084 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.1084   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Maryland and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart X--Michigan

0
14. Amend Sec.  52.1186 by:
0
a. In paragraph (e)(3), revising the second and third sentences;
0
b. Revising paragraph (e)(4);
0
c. In paragraph (e)(5), adding ``and Indian country within the borders 
of the State'' after ``in the State''; and
0
d. Adding paragraph (f).
    The revision and addition read as follows:


Sec.  52.1186   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (e) * * *
    (3) * * * The obligation to comply with such requirements with 
regard to sources and units in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
will be eliminated by the promulgation of an approval by the

[[Page 20191]]

Administrator of a revision to Michigan's State Implementation Plan 
(SIP) as correcting the SIP's deficiency that is the basis for the 
CSAPR Federal Implementation Plan (FIP) under Sec.  52.38(b)(1) 
and(b)(2)(iii) for those sources and units, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in areas of Indian country within the borders of the State not subject 
to the State's SIP authority will not be eliminated by the promulgation 
of an approval by the Administrator of a revision to Michigan's SIP.
    (4) Notwithstanding the provisions of paragraph (e)(3) of this 
section, if, at the time of the approval of Michigan's SIP revision 
described in paragraph (e)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
* * * * *
    (f) The owner and operator of each source located in the State of 
Michigan and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart Y--Minnesota

0
15. Amend Sec.  52.1240 by adding paragraphs (d) and (e) to read as 
follows:


Sec.  52.1240   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (d)(1) The owner and operator of each source and each unit located 
in the State of Minnesota and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Minnesota's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Minnesota's SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Minnesota's SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (e) The owner and operator of each source located in the State of 
Minnesota and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart Z--Mississippi

0
16. Amend Sec.  52.1284 by:
0
a. Redesignating paragraphs (a) through (c) as paragraphs (a)(1) 
through (3);
0
b. In newly redesignated paragraph (a)(2), removing ``2017 and each 
subsequent year.'' and adding in its place ``2017 through 2022.'', and 
removing the second and third sentences;
0
c. Revising newly redesignated paragraph (a)(3); and
0
d. Adding paragraphs (a)(4) and (5) and (b).
    The revision and additions read as follows:


Sec.  52.1284   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Mississippi and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Mississippi's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Mississippi's SIP.
    (4) Notwithstanding the provisions of paragraph (a)(3) of this 
section, if, at the time of the approval of Mississippi's SIP revision 
described in paragraph (a)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (a)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of

[[Page 20192]]

CSAPR NOX Ozone Season Group 2 allowances between certain 
accounts under common control), the provisions of Sec.  97.826(e) of 
this chapter (concerning the conversion of amounts of unused CSAPR 
NOX Ozone Season Group 2 allowances allocated for control 
periods before 2023 to different amounts of CSAPR NOX Ozone 
Season Group 3 allowances), and the provisions of Sec.  97.811(e) of 
this chapter (concerning the recall of CSAPR NOX Ozone 
Season Group 2 allowances equivalent in quantity and usability to all 
such allowances allocated to units in the State and Indian country 
within the borders of the State for control periods after 2022) shall 
continue to apply.
    (b) The owner and operator of each source located in the State of 
Mississippi and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart AA--Missouri

0
17. Amend Sec.  52.1326 by revising paragraph (b)(2) and (3) and adding 
paragraphs (b)(4) and (5) and (c) to read as follows:


Sec.  52.1326   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (b) * * *
    (2) The owner and operator of each source and each unit located in 
the State of Missouri and for which requirements are set forth under 
the CSAPR NOX Ozone Season Group 2 Trading Program in 
subpart EEEEE of part 97 of this chapter must comply with such 
requirements with regard to emissions occurring in 2017 through 2022. 
The obligation to comply with such requirements will be eliminated by 
the promulgation of an approval by the Administrator of a revision to 
Missouri's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(ii), except to the extent the 
Administrator's approval is partial or conditional.
    (3) The owner and operator of each source and each unit located in 
the State of Missouri and for which requirements are set forth under 
the CSAPR NOX Ozone Season Group 3 Trading Program in 
subpart GGGGG of part 97 of this chapter must comply with such 
requirements with regard to emissions occurring in 2023 and each 
subsequent year. The obligation to comply with such requirements will 
be eliminated by the promulgation of an approval by the Administrator 
of a revision to Missouri's State Implementation Plan (SIP) as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan (FIP) under Sec.  52.38(b)(1) and (b)(2)(iii), 
except to the extent the Administrator's approval is partial or 
conditional.
    (4) Notwithstanding the provisions of paragraphs (b)(2) and (3) of 
this section, if, at the time of the approval of Missouri's SIP 
revision described in paragraph (b)(2) or (3) of this section, the 
Administrator has already started recording any allocations of CSAPR 
NOX Ozone Season Group 2 allowances or CSAPR NOX 
Ozone Season Group 3 allowances under subpart EEEEE or GGGGG, 
respectively, of part 97 of this chapter to units in the State for a 
control period in any year, the provisions of such subpart authorizing 
the Administrator to complete the allocation and recordation of such 
allowances to such units for each such control period shall continue to 
apply, unless provided otherwise by such approval of the State's SIP 
revision.
    (5) Notwithstanding the provisions of paragraph (b)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts of unused CSAPR NOX Ozone Season Group 
2 allowances allocated for control periods before 2023 to different 
amounts of CSAPR NOX Ozone Season Group 3 allowances), and 
the provisions of Sec.  97.811(e) of this chapter (concerning the 
recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all such allowances allocated 
to units in the State for control periods after 2022) shall continue to 
apply.
    (c) The owner and operator of each source located in the State of 
Missouri and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart DD--Nevada

0
18. Add Sec.  52.1492 to read as follows:


Sec.  52.1492   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Nevada and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Nevada's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Nevada's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Nevada's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (b) The owner and operator of each source located in the State of 
Nevada and Indian country within the borders of the State and for which 
requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

[[Page 20193]]

Subpart FF--New Jersey

0
19. Amend Sec.  52.1584 by:
0
a. In paragraph (e)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (f).
    The addition reads as follows:


Sec.  52.1584   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (f) The owner and operator of each source located in the State of 
New Jersey and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart HH--New York

0
20. Amend Sec.  52.1684 by:
0
a. In paragraph (b)(3), revising the second and third sentences;
0
b. Revising paragraph (b)(4);
0
c. In paragraph (b)(5), adding ``and Indian country within the borders 
of the State'' after ``in the State''; and
0
d. Adding paragraph (c).
    The revision and addition read as follows:


Sec.  52.1684   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (b) * * *
    (3) * * * The obligation to comply with such requirements with 
regard to sources and units in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
will be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's State Implementation Plan 
(SIP) as correcting the SIP's deficiency that is the basis for the 
CSAPR Federal Implementation Plan (FIP) under Sec.  52.38(b)(1) 
and(b)(2)(iii) for those sources and units, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in areas of Indian country within the borders of the State not subject 
to the State's SIP authority will not be eliminated by the promulgation 
of an approval by the Administrator of a revision to New York's SIP.
    (4) Notwithstanding the provisions of paragraph (b)(3) of this 
section, if, at the time of the approval of New York's SIP revision 
described in paragraph (b)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
* * * * *
    (c) The owner and operator of each source located in the State of 
New York and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart KK--Ohio

0
21. Amend Sec.  52.1882 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.1882   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Ohio and for which requirements are set forth in Sec.  52.40 and Sec.  
52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart LL--Oklahoma

0
22. Amend Sec.  52.1930 by:
0
a. Redesignating paragraphs (a) through (c) as paragraphs (a)(1) 
through (3);
0
b. In newly redesignated paragraph (a)(2), removing ``2017 and each 
subsequent year.'' and adding in its place ``2017 through 2022.'', and 
removing the second and third sentences;
0
c. Revising newly redesignated paragraph (a)(3); and
0
c. Adding paragraphs (a)(4) and (5) and (b).
    The revision and additions read as follows:


Sec.  52.1930   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Oklahoma and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Oklahoma's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Oklahoma's SIP.
    (4) Notwithstanding the provisions of paragraph (a)(3) of this 
section, if, at the time of the approval of Oklahoma's SIP revision 
described in paragraph (a)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (a)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts

[[Page 20194]]

of unused CSAPR NOX Ozone Season Group 2 allowances 
allocated for control periods before 2023 to different amounts of CSAPR 
NOX Ozone Season Group 3 allowances), and the provisions of 
Sec.  97.811(e) of this chapter (concerning the recall of CSAPR 
NOX Ozone Season Group 2 allowances equivalent in quantity 
and usability to all such allowances allocated to units in the State 
and Indian country within the borders of the State for control periods 
after 2022) shall continue to apply.
    (b) The owner and operator of each source located in the State of 
Oklahoma and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart NN--Pennsylvania

0
23. Amend Sec.  52.2040 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.2040   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Pennsylvania and for which requirements are set forth in Sec.  52.40 
and Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 
must comply with such requirements with regard to emissions occurring 
in 2026 and each subsequent year.

Subpart RR--Tennessee

0
24. Amend Sec.  52.2240 by:
0
a. In paragraph (e)(2), removing ``2017 and each subsequent year.'' and 
adding in its place ``2017 through 2022.'', and removing the second 
sentence;
0
b. Revising paragraph (e)(3); and
0
c. Adding paragraphs (e)(4) and (5).
    The revision and additions read as follows:


Sec.  52.2240   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (e) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Tennessee and for which requirements are set forth under 
the CSAPR NOX Ozone Season Group 3 Trading Program in 
subpart GGGGG of part 97 of this chapter must comply with such 
requirements with regard to emissions occurring in 2023 and each 
subsequent year. The obligation to comply with such requirements will 
be eliminated by the promulgation of an approval by the Administrator 
of a revision to Tennessee's State Implementation Plan (SIP) as 
correcting the SIP's deficiency that is the basis for the CSAPR Federal 
Implementation Plan (FIP) under Sec.  52.38(b)(1) and (b)(2)(iii), 
except to the extent the Administrator's approval is partial or 
conditional.
    (4) Notwithstanding the provisions of paragraph (e)(3) of this 
section, if, at the time of the approval of Tennessee's SIP revision 
described in paragraph (e)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State for a control period in any year, the 
provisions of subpart GGGGG of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of CSAPR 
NOX Ozone Season Group 3 allowances to such units for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (e)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts of unused CSAPR NOX Ozone Season Group 
2 allowances allocated for control periods before 2023 to different 
amounts of CSAPR NOX Ozone Season Group 3 allowances), and 
the provisions of Sec.  97.811(e) of this chapter (concerning the 
recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all such allowances allocated 
to units in the State for control periods after 2022) shall continue to 
apply.

Subpart SS--Texas

0
25. Amend Sec.  52.2283 by:
0
a. In paragraph (d)(2), removing ``2017 and each subsequent year.'' and 
adding in its place ``2017 through 2022.'', and removing the second and 
third sentences;
0
b. Revising paragraph (d)(3); and
0
c. Adding paragraphs (d)(4) and (5) and (e).
    The revision and additions read as follows:


Sec.  52.2283   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (d) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Texas and Indian country within the borders of the State 
and for which requirements are set forth under the CSAPR NOX 
Ozone Season Group 3 Trading Program in subpart GGGGG of part 97 of 
this chapter must comply with such requirements with regard to 
emissions occurring in 2023 and each subsequent year. The obligation to 
comply with such requirements with regard to sources and units in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Texas' State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Texas' SIP.
    (4) Notwithstanding the provisions of paragraph (d)(3) of this 
section, if, at the time of the approval of Texas' SIP revision 
described in paragraph (d)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (d)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter

[[Page 20195]]

(concerning the conversion of amounts of unused CSAPR NOX 
Ozone Season Group 2 allowances allocated for control periods before 
2023 to different amounts of CSAPR NOX Ozone Season Group 3 
allowances), and the provisions of Sec.  97.811(e) of this chapter 
(concerning the recall of CSAPR NOX Ozone Season Group 2 
allowances equivalent in quantity and usability to all such allowances 
allocated to units in the State and Indian country within the borders 
of the State for control periods after 2022) shall continue to apply.
    (e) The owner and operator of each source located in the State of 
Texas and Indian country within the borders of the State and for which 
requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart TT--Utah

0
26. Add Sec.  52.2356 to read as follows:


Sec.  52.2356   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Utah and Indian country within the borders of the State 
and for which requirements are set forth under the CSAPR NOX 
Ozone Season Group 3 Trading Program in subpart GGGGG of part 97 of 
this chapter must comply with such requirements with regard to 
emissions occurring in 2023 and each subsequent year. The obligation to 
comply with such requirements with regard to sources and units in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Utah's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Utah's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Utah's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (b) The owner and operator of each source located in the State of 
Utah and Indian country within the borders of the State and for which 
requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart VV--Virginia

0
27. Amend Sec.  52.2440 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.2440   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
Virginia and for which requirements are set forth in Sec.  52.40 and 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart XX--West Virginia

0
28. Amend Sec.  52.2540 by:
0
a. In paragraph (b)(3), removing ``(b)(2)(v), except'' and adding in 
its place ``(b)(2)(iii), except''; and
0
b. Adding paragraph (c).
    The addition reads as follows:


Sec.  52.2540   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) The owner and operator of each source located in the State of 
West Virginia and for which requirements are set forth in Sec.  52.40 
and Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 
must comply with such requirements with regard to emissions occurring 
in 2026 and each subsequent year.

Subpart YY--Wisconsin

0
29. Amend Sec.  52.2587 by:
0
a. In paragraph (e)(2), removing ``2017 and each subsequent year.'' and 
adding in its place ``2017 through 2022.'', and removing the second and 
third sentences;
0
b. Revising paragraph (e)(3); and
0
c. Adding paragraphs (e)(4) and (5) and (f).
    The revision and additions read as follows:


Sec.  52.2587   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (e) * * *
    (3) The owner and operator of each source and each unit located in 
the State of Wisconsin and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Wisconsin's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wisconsin's SIP.
    (4) Notwithstanding the provisions of paragraph (e)(3) of this 
section, if, at the time of the approval of Wisconsin's SIP revision 
described in paragraph (e)(3) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart

[[Page 20196]]

GGGGG of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of CSAPR NOX Ozone 
Season Group 3 allowances to such units for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.
    (5) Notwithstanding the provisions of paragraph (e)(2) of this 
section, after 2022 the provisions of Sec.  97.826(c) of this chapter 
(concerning the transfer of CSAPR NOX Ozone Season Group 2 
allowances between certain accounts under common control), the 
provisions of Sec.  97.826(e) of this chapter (concerning the 
conversion of amounts of unused CSAPR NOX Ozone Season Group 
2 allowances allocated for control periods before 2023 to different 
amounts of CSAPR NOX Ozone Season Group 3 allowances), and 
the provisions of Sec.  97.811(e) of this chapter (concerning the 
recall of CSAPR NOX Ozone Season Group 2 allowances 
equivalent in quantity and usability to all such allowances allocated 
to units in the State and Indian country within the borders of the 
State for control periods after 2022) shall continue to apply.
    (f) The owner and operator of each source located in the State of 
Wisconsin and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart ZZ--Wyoming

0
30. Add Sec.  52.2638 to read as follows:


Sec.  52.2638   Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Wyoming and Indian country within the borders of the 
State and for which requirements are set forth under the CSAPR 
NOX Ozone Season Group 3 Trading Program in subpart GGGGG of 
part 97 of this chapter must comply with such requirements with regard 
to emissions occurring in 2023 and each subsequent year. The obligation 
to comply with such requirements with regard to sources and units in 
the State and areas of Indian country within the borders of the State 
subject to the State's SIP authority will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Wyoming State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the CSAPR Federal Implementation Plan 
(FIP) under Sec.  52.38(b)(1) and (b)(2)(iii) for those sources and 
units, except to the extent the Administrator's approval is partial or 
conditional. The obligation to comply with such requirements with 
regard to sources and units located in areas of Indian country within 
the borders of the State not subject to the State's SIP authority will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wyoming's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Wyoming's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of CSAPR NOX Ozone 
Season Group 3 allowances under subpart GGGGG of part 97 of this 
chapter to units in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for a control 
period in any year, the provisions of subpart GGGGG of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of CSAPR NOX Ozone Season Group 3 allowances to 
such units for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.
    (b) The owner and operator of each source located in the State of 
Wyoming and Indian country within the borders of the State and for 
which requirements are set forth in Sec.  52.40 and Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, or Sec.  52.45 must comply with such 
requirements with regard to emissions occurring in 2026 and each 
subsequent year.

PART 75--CONTINUOUS EMISSION MONITORING

0
31. The authority citation for part 75 is revised to read as follows:

    Authority:  42 U.S.C. 7401-7671q and 7651k note.

0
32. Amend Sec.  75.72 by:
0
a. In paragraph (c)(3), removing ``appendix B of this part.'' and 
adding in its place ``appendix B to this part.'';
0
b. In paragraph (e)(1)(ii), removing ``heat input from'' and adding in 
its place ``heat input rate to'';
0
c. In paragraph (e)(2), removing ``appendix D of this part'' and adding 
in its place ``appendix D to this part''; and
0
d. Adding paragraph (f).
    The addition reads as follows:


Sec.  75.72   Determination of NOX mass emissions for common stack and 
multiple stack configurations.

* * * * *
    (f) Procedures for apportioning hourly NOX mass emission rate to 
the unit level. If the owner or operator of a unit determining hourly 
NOX mass emission rate at a common stack under this section 
is subject to a State or federal NOX mass emissions 
reduction program under subpart GGGGG of part 97 of this chapter or 
under a state implementation plan approved pursuant to Sec.  
52.38(b)(12) of this chapter, then on and after January 1, 2024, the 
owner or operator shall apportion the hourly NOX mass 
emissions rate at the common stack to each unit using the common stack 
based on the ratio of the hourly heat input rate for each such unit to 
the total hourly heat input rate for all such units, in conjunction 
with the appropriate unit and stack operating times, according to the 
procedures in section 8.5.3 of appendix F to this part.
* * * * *
0
33. Amend Sec.  75.73 by:
0
a. Revising paragraph (a)(3);
0
b. In paragraph (c)(1), removing ``NoX emissions'' and 
adding in its place ``NOX emissions'';
0
c. Adding a paragraph heading to paragraph (c)(2);
0
d. Revising paragraphs (c)(3) and (f)(1) introductory text;
0
e. Removing and reserving paragraph (f)(1)(i)(B);
0
f. In paragraph (f)(1)(ii)(G), removing ``appendix D;'' and adding in 
its place ``appendix D to this part;'';
0
g. Adding paragraphs (f)(1)(ix) and (x);
0
h. Adding a paragraph heading to paragraph (f)(2); and
0
i. Revising paragraph (f)(4).
    The revisions and addition reads as follows:


Sec.  75.73   Recordkeeping and reporting.

* * * * *
    (a) * * *
    (3) For each hour when the unit is operating, NOX mass 
emission rate, calculated in accordance with section 8 of appendix F to 
this part.
* * * * *
    (c) * * *
    (2) Monitoring plan updates. * * *
    (3) Contents of the monitoring plan. Each monitoring plan shall 
contain the information in Sec.  75.53(g)(1) in electronic format and 
the information in Sec.  75.53(g)(2) in hardcopy format. In addition, 
to the extent applicable, each monitoring plan shall contain the 
information in Sec.  75.53(h)(1)(i) and (h)(2)(i) in electronic format 
and the information in Sec.  75.53(h)(1)(ii) and (h)(2)(ii) in hardcopy 
format. For units using the low mass emissions excepted methodology 
under Sec.  75.19, the monitoring plan shall include the additional 
information in Sec.  75.53(h)(4)(i) and (h)(4)(ii). The monitoring plan 
also

[[Page 20197]]

shall include a seasonal controls indicator and an ozone season fuel-
switching flag.
    (f) * * *
    (1) Electronic submission. The designated representative for an 
affected unit shall electronically report the data and information in 
this paragraph (f)(1) and in paragraphs (f)(2) and (3) of this section 
to the Administrator quarterly, unless the unit has been placed in 
long-term cold storage (as defined in Sec.  72.2 of this chapter). Each 
electronic report must be submitted to the Administrator within 30 days 
following the end of each calendar quarter. Each electronic report 
shall include the information provided in paragraphs (f)(1)(i) through 
(x) of this section and shall also include the date of report 
generation. A unit placed into long-term cold storage is exempted from 
submitting quarterly reports beginning with the calendar quarter 
following the quarter in which the unit is placed into long-term cold 
storage, provided that the owner or operator shall submit quarterly 
reports for the unit beginning with the data from the quarter in which 
the unit recommences operation (where the initial quarterly report 
contains hourly data beginning with the first hour of recommenced 
operation of the unit).
* * * * *
    (ix) On and after on January 1, 2024, for a unit subject to subpart 
GGGGG of part 97 of this chapter or a state implementation plan 
approved under Sec.  52.38(b)(12) of this chapter and determining 
NOX mass emission rate at a common stack, apportioned hourly 
NOX mass emission rate for the unit, lb/hr.
    (x) On and after January 1, 2024, for a unit subject to a backstop 
daily NOX emission rate under subpart GGGGG of part 97 of 
this chapter or under a state implementation plan approved under Sec.  
52.38(b)(12) of this chapter:
    (A) Daily NOX emissions (lbs) for each day of the 
reporting period;
    (B) Daily heat input (mmBtu) for each day of the reporting period;
    (C) Daily average NOX emission rate (lb/mmBtu, rounded 
to the nearest thousandth) for each day of the reporting period;
    (D) Daily NOX emissions (lbs) exceeding the applicable 
backstop daily NOX emission rate for each day of the 
reporting period; and
    (E) Cumulative NOX emissions (tons, rounded to the 
nearest tenth) exceeding the applicable backstop daily NOX 
emission rate during the ozone season.
    (2) Verification of identification codes and formulas. * * *
* * * * *
    (4) Electronic format, method of submission, and explanatory 
information. The designated representative shall comply with all of the 
quarterly reporting requirements in Sec.  75.64(d), (f), and (g).
0
34. Revise Sec.  75.75 to read as follows:


Sec.  75.75  Additional ozone season calculation procedures.

    (a) The owner or operator of a unit that is required to calculate 
daily or ozone season heat input shall do so by summing the unit's 
hourly heat input determined according to the procedures in this part 
for all hours in which the unit operated during the day or ozone 
season.
    (b) The owner or operator of a unit that is required to determine 
daily or ozone season NOX emission rate (in lbs/mmBtu) shall 
do so by dividing daily or ozone season NOX mass emissions 
(in lbs) determined in accordance with this subpart, by daily or ozone 
season heat input determined in accordance with paragraph (a) of this 
section.
0
35. Amend appendix F to part 75 by:
0
a. Adding section 5.3.3;
0
b. In section 8.1.2, revising the introductory text preceding Equation 
F-25;
0
c. In section 8.4, revising the introductory text, paragraph (a) 
introductory text (preceding Equation F-27), and paragraph (b) 
introductory text (preceding Equation F-27a), and adding paragraph (c);
0
d. In section 8.5.2, removing ``the hourly NOX mass 
emissions at each unit'' and adding in its place ``hourly 
NOX mass emissions at the common stack.''; and
0
e. Adding section 8.5.3.
    The additions and revisions read as follows

Appendix F to Part 75--Conversion Procedures

* * * * *
    5.3.3 Calculate total daily heat input for a unit using a flow 
monitor and diluent monitor to calculate heat input, using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP06AP22.006

Where:

HId = Total heat input for a unit for the day, mmBtu.
HIh = Heat input rate for the unit for hour ``h'' from Equation F-
15, F-16, F-17, F-18, F-21a, or F-21b, mmBtu/hr.
th = Unit operating time, fraction of the hour (0.00 to 1.00, in 
equal increments from one hundredth to one quarter of an hour, at 
the option of the owner or operator).
h = Designation of a particular hour.
* * * * *
    8.1.2 If NOX emission rate is measured at a common stack 
and heat input rate is measured at the unit level, calculate the hourly 
heat input rate at the common stack according to the following formula:
* * * * *
    8.4 Use the following equations to calculate daily, quarterly, 
cumulative ozone season, and cumulative year-to-date NOX 
mass emissions:
    (a) When hourly NOX mass emissions are reported in lb., 
use Eq. F-27 to calculate quarterly, cumulative ozone season, and 
cumulative year-to-date NOX mass emissions in tons. * * *
    (b) When hourly NOX mass emission rate is reported in 
lb/hr, use Eq. F-27a to calculate quarterly, cumulative ozone season, 
and cumulative year-to-date NOX mass emissions in tons. * * 
*
    (c) To calculate daily NOX mass emissions for a unit in 
pounds, use Eq. F-27b.

[[Page 20198]]

[GRAPHIC] [TIFF OMITTED] TP06AP22.007

Where:

M(NOX)d = NOX mass emissions for a unit for the day, 
pounds.
E(NOX)h = NOX mass emission rate for the unit for hour 
``h'' from Equation F-24a, F-26a, F-26b, or F-28, lb/hr.
th = Unit operating time, fraction of the hour (0.00 to 1.00, in 
equal increments from one hundredth to one quarter of an hour, at 
the option of the owner or operator).
h = Designation of a particular hour.
* * * * *
    8.5.3 Where applicable, the owner or operator of a unit that 
determines hourly NOX mass emission rate at a common stack 
shall apportion hourly NOX mass emissions rate to the units 
using the common stack based on the hourly heat input rate, using 
Equation F-28:
[GRAPHIC] [TIFF OMITTED] TP06AP22.008

Where:

E(NOX)i = Apportioned NOX mass emission rate for unit 
``i'', lb/hr.
E(NOX)CS = NOX mass emission rate at the common stack, 
lb/hr.
HIi = Heat input rate for unit ``i'', mmBtu/hr.
ti = Operating time for unit ``i'', fraction of the hour (0.00 to 
1.00, in equal increments from one hundredth to one quarter of an 
hour, at the option of the owner or operator).
tCS = Common stack operating time, fraction of the hour (0.00 to 
1.00, in equal increments from one hundredth to one quarter of an 
hour, at the option of the owner or operator).
n = Number of units using the common stack.
i = Designation of a particular unit.

PART 78--APPEAL PROCEDURES

0
36. The authority citation for part 78 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

0
37. Amend Sec.  78.1 by:
0
a. In paragraph (b)(17)(viii), adding ``or (e)'' after ``Sec.  
97.826(d)'';
0
b. In paragraph (b)(17)(ix), adding ``or (e)'' after ``Sec.  
97.811(d)''; and
0
c. Revising paragraph (b)(19).
    The revision reads as follows:


Sec.  78.1  Purpose and scope.

* * * * *
    (b) * * *
    (19) Under subpart GGGGG of part 97 of this chapter,
    (i) The decision on the calculation of a state CSAPR NOX 
Ozone Season Group 3 trading budget under Sec.  97.1010(a)(3) of this 
chapter.
    (ii) The decision on the allocation of CSAPR NOX Ozone 
Season Group 3 allowances under Sec.  97.1011 or Sec.  97.1012 of this 
chapter.
    (iii) The decision on the transfer of CSAPR NOX Ozone 
Season Group 3 allowances under Sec.  97.1023 of this chapter.
    (iv) The decision on the deduction of CSAPR NOX Ozone 
Season Group 3 allowances under Sec.  97.1024, Sec.  97.1025, or Sec.  
97.1026(d) of this chapter.
    (v) The correction of an error in an Allowance Management System 
account under Sec.  97.1027 of this chapter.
    (vi) The adjustment of information in a submission and the decision 
on the deduction and transfer of CSAPR NOX Ozone Season 
Group 3 allowances based on the information as adjusted under Sec.  
97.1028 of this chapter.
    (vii) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (viii) The approval or disapproval of a petition under Sec.  
97.1035 of this chapter.
* * * * *

PART 97--FEDERAL NOX BUDGET TRADING PROGRAM, CAIR NOX AND SO2 
TRADING PROGRAMS, CSAPR NOX AND SO2 TRADING PROGRAMS, AND TEXAS SO2 
TRADING PROGRAM

0
38. The authority citation for part 97 continues to read as follows:

    Authority:  42 U.S.C. 7401, 7403, 7410, 7426, 7491, 7601, and 
7651, et seq.

Subpart AAAAA--CSAPR NOX Annual Trading Program


Sec.  97.402   [Amended]

0
39. Amend Sec.  97.402 by:
0
a. In the definition of ``CSAPR NOX Ozone Season Group 1 
Trading Program'', removing ``(b)(2)(i) and (ii), and'' and adding in 
its place ``(b)(2)(i), and'';
0
b. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and''; and
0
c. In the definition of ``CSAPR NOX Ozone Season Group 3 
Trading Program'', removing ``(b)(2)(v), and'' and adding in its place 
``(b)(2)(iii), and'';


Sec.  97.411   [Amended]

0
40. Amend Sec.  97.411 by:
0
a. In paragraphs (b)(1)(i)(A) and (B), removing ``State, in 
accordance'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, in accordance''; and
0
b. In paragraphs (b)(2)(i)(A) and (B), removing ``Indian country within 
the borders of a State, in accordance'' and adding in its place ``areas 
of Indian country within the borders of a State not subject to the 
State's SIP authority, in accordance''.


Sec.  97.412   [Amended]

0
41. Amend Sec.  97.412 by:
0
a. In paragraph (a) introductory text, removing ``State, the 
Administrator'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, the Administrator'';
0
b. In paragraphs (a)(3)(iii) and (a)(5), adding ``and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority'' after ``in the State'';
0
c. In paragraph (a)(10), removing ``State, is allocated'' and adding in 
its place ``State and areas of Indian country

[[Page 20199]]

within the borders of the State subject to the State's SIP authority, 
is allocated'';
0
d. In paragraph (b) introductory text, removing ``Indian country within 
the borders of each State, the Administrator'' and adding in its place 
``areas of Indian country within the borders of each State not subject 
to the State's SIP authority, the Administrator''; and
0
e. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority''.


Sec.  97.421   [Amended]

0
42. In Sec.  97.421, amend paragraph (f)(2) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.


Sec.  97.426   [Amended]

0
43. In Sec.  97.426, amend paragraph (c) by removing ``State (or 
Indian'' and adding in its place ``State (and Indian''.

Subpart BBBBB--CSAPR NOX Ozone Season Group 1 Trading Program


Sec.  97.502   [Amended]

0
44. Amend Sec.  97.502 by:
0
a. In the definition of ``CSAPR NOX Ozone Season Group 1 
Trading Program'', removing ``(b)(2)(i) and (ii), and'' and adding in 
its place ``(b)(2)(i), and'';
0
b. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
c. In the definition of ``CSAPR NOX Ozone Season Group 3 
allowance'', adding ``or (e)'' after ``Sec.  97.826(d)'', and adding 
``or less'' after ``one ton'';
0
d. In the definition of ``CSAPR NOX Ozone Season Group 3 
Trading Program'', removing ``(b)(2)(v), and'' and adding in its place 
``(b)(2)(iii), and''; and
0
e. In the definition of ``State'', removing ``(b)(2)(i) and (ii), and'' 
and adding in its place ``(b)(2)(i), and''.


Sec.  97.511   [Amended]

0
45. Amend Sec.  97.511 by:
0
a. In paragraphs (b)(1)(i)(A) and (B), removing ``State, in 
accordance'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, in accordance''; and
0
b. In paragraphs (b)(2)(i)(A) and (B), removing ``Indian country within 
the borders of a State, in accordance'' and adding in its place ``areas 
of Indian country within the borders of a State not subject to the 
State's SIP authority, in accordance''.


Sec.  97.512   [Amended]

0
46. Amend Sec.  97.512 by:
0
a. In paragraph (a) introductory text, removing ``State, the 
Administrator'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, the Administrator'';
0
b. In paragraphs (a)(3)(iii) and (a)(5), adding ``and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority'' after ``in the State'';
0
c. In paragraph (a)(10), removing ``State, is allocated'' and adding in 
its place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority, is allocated'';
0
d. In paragraph (b) introductory text, removing ``Indian country within 
the borders of each State, the Administrator'' and adding in its place 
``areas of Indian country within the borders of each State not subject 
to the State's SIP authority, the Administrator''; and
0
e. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority''.


Sec.  97.521   [Amended]

0
47. In Sec.  97.521, amend paragraph (f)(2) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.
0
48. Amend Sec.  97.526 by:
0
a. In paragraph (c), removing ``State (or Indian'' and adding in its 
place ``State (and Indian'';
0
b. In paragraph (d)(1) introductory text, removing ``Sec.  
52.38(b)(2)(i) of this chapter (or'' and adding in its place ``Sec.  
52.38(b)(2)(i)(A) of this chapter (and'';
0
c. In paragraph (d)(1)(ii), removing ``except a State listed in Sec.  
52.38(b)(2)(i)'' and adding in its place ``listed in Sec.  
52.38(b)(2)(ii)'';
0
d. In paragraph (d)(1)(iv), removing ``Sec.  52.38(b)(2)(iii) or (iv) 
of this chapter (or'' and adding in its place ``Sec.  52.38(b)(2)(ii) 
of this chapter (and'';
0
e. Revising paragraph (d)(2)(i);
0
f. In paragraph (d)(2)(ii), removing ``Sec.  52.38(b)(2)(v) of this 
chapter (or'' and adding in its place ``Sec.  52.38(b)(2)(iii)(A) of 
this chapter (and'';
0
g. Adding paragraph (d)(2)(iii);
0
h. In paragraph (e)(1), removing ``chapter (or Indian'' and adding in 
its place ``chapter (and Indian'';
0
i. In paragraph (e)(2), removing ``Sec.  52.38(b)(2)(iv) of this 
chapter (or'' and adding in its place ``Sec.  52.38(b)(2)(iii)(A) of 
this chapter (and''; and
0
j. Adding paragraph (e)(3).
    The revisions and additions read as follows:


Sec.  97.526   Banking and conversion.

* * * * *
    (d) * * *
    (2)(i) Except as provided in paragraphs (d)(2)(ii) and (iii) of 
this section, after the Administrator has carried out the procedures 
set forth in paragraph (d)(1) of this section, upon any determination 
that would otherwise result in the initial recordation of a given 
number of CSAPR NOX Ozone Season Group 1 allowances in the 
compliance account for a source in a State listed in Sec.  
52.38(b)(2)(ii) of this chapter (and Indian country within the borders 
of such a State), the Administrator will not record such CSAPR 
NOX Ozone Season Group 1 allowances but instead will 
allocate and record in such account an amount of CSAPR NOX 
Ozone Season Group 2 allowances for the control period in 2017 computed 
as the quotient, rounded up to the nearest allowance, of such given 
number of CSAPR NOX Ozone Season Group 1 allowances divided 
by the conversion factor determined under paragraph (d)(1)(ii) of this 
section.
* * * * *
    (iii) After the Administrator has carried out the procedures set 
forth in paragraph (d)(1) of this section and Sec.  97.826(e)(1), upon 
any determination that would otherwise result in the initial 
recordation of a given number of CSAPR NOX Ozone Season 
Group 1 allowances in the compliance account for a source in a State 
listed in Sec.  52.38(b)(2)(iii)(B) of this chapter (and Indian country 
within the borders of such a State), the Administrator will not record 
such CSAPR NOX Ozone Season Group 1 allowances but instead 
will allocate and record in such account an amount of CSAPR 
NOX Ozone Season Group 3 allowances for the control period 
in 2023 computed as the quotient, rounded up to the nearest allowance, 
of such given number of CSAPR NOX Ozone Season Group 1 
allowances divided by the conversion factor determined under paragraph 
(d)(1)(ii) of this section and further divided by the conversion factor 
determined under Sec.  97.826(e)(1)(ii).
* * * * *
    (e) * * *
    (3) After the Administrator has carried out the procedures set 
forth in paragraph (d)(1) of this section and Sec.  97.826(e)(1), the 
owner or operator of a CSAPR NOX Ozone Season Group 1

[[Page 20200]]

source in a State listed in Sec.  52.38(b)(2)(iii)(B) of this chapter 
(and Indian country within the borders of such a State) may satisfy a 
requirement to hold a given number of CSAPR NOX Ozone Season 
Group 1 allowances for the control period in 2015 or 2016 by holding 
instead, in a general account established for this sole purpose, an 
amount of CSAPR NOX Ozone Season Group 3 allowances for the 
control period in 2023 (or any later control period for which the 
allowance transfer deadline defined in Sec.  97.1002 has passed) 
computed as the quotient, rounded up to the nearest allowance, of such 
given number of CSAPR NOX Ozone Season Group 1 allowances 
divided by the conversion factor determined under paragraph (d)(1)(ii) 
of this section and further divided by the conversion factor determined 
under Sec.  97.826(e)(1)(ii).

Subpart CCCCC--CSAPR SO2 Group 1 Trading Program


Sec.  97.602   [Amended]

0
49. Amend Sec.  97.602 by:
0
a. In the definition of ``CSAPR NOX Ozone Season Group 1 
Trading Program'', removing ``(b)(2)(i) and (ii), and'' and adding in 
its place ``(b)(2)(i), and'';
0
b. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
c. In the definition of ``CSAPR NOX Ozone Season Group 3 
Trading Program'', removing ``(b)(2)(v), and'' and adding in its place 
``(b)(2)(iii), and'';


Sec.  97.611   [Amended]

0
50. Amend Sec.  97.611 by:
0
a. In paragraphs (b)(1)(i)(A) and (B), removing ``State, in 
accordance'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, in accordance''; and
0
b. In paragraphs (b)(2)(i)(A) and (B), removing ``Indian country within 
the borders of a State, in accordance'' and adding in its place ``areas 
of Indian country within the borders of a State not subject to the 
State's SIP authority, in accordance''.


Sec.  97.612   [Amended]

0
51. Amend Sec.  97.612 by:
0
a. In paragraph (a) introductory text, removing ``State, the 
Administrator'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, the Administrator'';
0
b. In paragraphs (a)(3)(iii) and (a)(5), adding ``and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority'' after ``in the State'';
0
c. In paragraph (a)(10), removing ``State, is allocated'' and adding in 
its place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority, is allocated'';
0
d. In paragraph (b) introductory text, removing ``Indian country within 
the borders of each State, the Administrator'' and adding in its place 
``areas of Indian country within the borders of each State not subject 
to the State's SIP authority, the Administrator''; and
0
e. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority''.


Sec.  97.621   [Amended]

0
52. In Sec.  97.621, amend paragraph (f)(2) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.


Sec.  97.626   [Amended]

0
53. In Sec.  97.626, amend paragraph (c) by removing ``State (or 
Indian'' and adding in its place ``State (and Indian''.

Subpart DDDDD--CSAPR SO2 Group 2 Trading Program

0
54. Amend Sec.  97.702 by:
0
a. In the definition of ``alternate designated representative'', 
removing ``or CSAPR NOX Ozone Season Group 2 Trading 
Program, then'' and adding in its place ``CSAPR NOX Ozone 
Season Group 2 Trading Program, or CSAPR NOX Ozone Season 
Group 3 Trading Program, then'';
0
b. In the definition of ``CSAPR NOX Ozone Season Group 1 
Trading Program'', removing ``(b)(2)(i) and (ii), and'' and adding in 
its place ``(b)(2)(i), and'';
0
c. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
d. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 3 Trading Program''; and
0
e. In the definition of ``designated representative'', removing ``or 
CSAPR NOX Ozone Season Group 2 Trading Program, then'' and 
adding in its place ``CSAPR NOX Ozone Season Group 2 Trading 
Program, or CSAPR NOX Ozone Season Group 3 Trading Program, 
then''.


Sec.  97.702   Definitions.

* * * * *
    CSAPR NOX Ozone Season Group 3 Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart GGGGG of this part and Sec.  
52.38(b)(1), (b)(2)(iii), and (b)(10) through (14) and (17) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(b)(10) or (11) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(b)(12) of this chapter), as a means of 
mitigating interstate transport of ozone and NOX.
* * * * *


Sec.  97.711  [Amended]

0
55. Amend Sec.  97.711 by:
0
a. In paragraphs (b)(1)(i)(A) and (B), removing ``State, in 
accordance'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, in accordance''; and
0
b. In paragraphs (b)(2)(i)(A) and (B), removing ``Indian country within 
the borders of a State, in accordance'' and adding in its place ``areas 
of Indian country within the borders of a State not subject to the 
State's SIP authority, in accordance''.


Sec.  97.712   [Amended]

0
56. Amend Sec.  97.712 by:
0
a. In paragraph (a) introductory text, removing ``State, the 
Administrator'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, the Administrator'';
0
b. In paragraphs (a)(3)(iii) and (a)(5), adding ``and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority'' after ``in the State'';
0
c. In paragraph (a)(10), removing ``State, is allocated'' and adding in 
its place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority, is allocated'';
0
d. In paragraph (b) introductory text, removing ``Indian country within 
the borders of each State, the Administrator'' and adding in its place 
``areas of Indian country within the borders of each State not subject 
to the State's SIP authority, the Administrator''; and
0
e. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority''.

[[Page 20201]]

Sec.  97.721   [Amended]

0
57. In Sec.  97.721, amend paragraph (f)(2) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.


Sec.  97.726   [Amended]

0
58. In Sec.  97.726, amend paragraph (c) by removing ``State (or 
Indian'' and adding in its place ``State (and Indian''.


Sec.  97.734   [Amended]

0
59. In Sec.  97.734, amend paragraph (d)(3) by removing ``or CSAPR 
NOX Ozone Season Group 2 Trading Program, quarterly'' and 
adding in its place ``CSAPR NOX Ozone Season Group 2 Trading 
Program, or CSAPR NOX Ozone Season Group 3 Trading Program, 
quarterly''.

Subpart EEEEE--CSAPR NOX Ozone Season Group 2 Trading Program

0
60. Amend Sec.  97.802 by:
0
a. In the definition of ``assurance account'', removing ``base CSAPR'' 
and adding in its place ``CSAPR'';
0
b. Removing the definitions for ``base CSAPR NOX Ozone 
Season Group 2 source'' and ``base CSAPR NOX Ozone Season 
Group 2 unit'';
0
c. In the definition of ``common designated representative'', removing 
``base CSAPR'' and adding in its place ``CSAPR'';
0
d. In the definition of ``common designated representative's assurance 
level'', revising paragraph (1);
0
e. In the definition of ``common designated representative's share'', 
removing ``base CSAPR'' and adding in its place ``CSAPR'' each time it 
appears;
0
f. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
g. In the definition of ``CSAPR NOX Ozone Season Group 3 
allowance'', adding ``or (e)'' after ``Sec.  97.826(d)'', and adding 
``or less'' after ``one ton'';
0
h. In the definition of ``CSAPR NOX Ozone Season Group 3 
Trading Program'', removing ``(b)(2)(v), and'' and adding in its place 
``(b)(2)(iii), and''; and
0
i. In the definition of ``State'', removing ``(b)(2)(iii) and (iv), 
and'' and adding in its place ``(b)(2)(ii), and''.
    The revision reads as follows:


Sec.  97.802   Definitions.

* * * * *
    Common designated representative's assurance level * * *
    (1) The amount (rounded to the nearest allowance) equal to the sum 
of the total amount of CSAPR NOX Ozone Season Group 2 
allowances allocated for such control period to the group of one or 
more CSAPR NOX Ozone Season Group 2 units in such State (and 
such Indian country) having the common designated representative for 
such control period and the total amount of CSAPR NOX Ozone 
Season Group 2 allowances purchased by an owner or operator of such 
CSAPR NOX Ozone Season Group 2 units in an auction for such 
control period and submitted by the State or the permitting authority 
to the Administrator for recordation in the compliance accounts for 
such CSAPR NOX Ozone Season Group 2 units in accordance with 
the CSAPR NOX Ozone Season Group 2 allowance auction 
provisions in a SIP revision approved by the Administrator under Sec.  
52.38(b)(8) or (9) of this chapter, multiplied by the sum of the State 
NOX Ozone Season Group 2 trading budget under Sec.  
97.810(a) and the State's variability limit under Sec.  97.810(b) for 
such control period, and divided by such State NOX Ozone 
Season Group 2 trading budget;
* * * * *


Sec.  97.806   [Amended]

0
61. In Sec.  97.806, amend paragraphs (c)(2)(i) introductory text, 
(c)(2)(i)(B), (c)(2)(iii) and (iv), and (c)(3)(ii) by removing ``base 
CSAPR'' and adding in its place ``CSAPR'' each time it appears.


Sec.  97.810   [Amended]

0
62. In Sec.  97.810, amend paragraphs (a)(1)(i) through (iii), 
(a)(2)(i) and (ii), (a)(12)(i) through (iii), (a)(13)(i) and (ii), 
(a)(17)(i) through (iii), (a)(19)(i) and (ii), (a)(20)(i) through 
(iii), (a)(23)(i) through (iii), and (b)(1), (2), (12), (13), (17), 
(19), (20), and (23) by removing ``and thereafter'' and adding in its 
place ``through 2022''.
0
63. Amend Sec.  97.811 by:
0
a. In paragraphs (b)(1)(i)(A) and (B), removing ``State, in 
accordance'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, in accordance'';
0
b. In paragraphs (b)(2)(i)(A) and (B), removing ``Indian country within 
the borders of a State, in accordance'' and adding in its place ``areas 
of Indian country within the borders of a State not subject to the 
State's SIP authority, in accordance'';
0
c. In paragraph (d)(1), removing ``Sec.  52.38(b)(2)(iv) of this 
chapter (or'' and adding in its place ``Sec.  52.38(b)(2)(ii)(B) of 
this chapter (and''; and
0
d. Adding paragraph (e).
    The addition reads as follows:


Sec.  97.811   Timing requirements for CSAPR NOX Ozone Season Group 2 
allowance allocations.

* * * * *
    (e) Recall of CSAPR NOX Ozone Season Group 2 allowances allocated 
for control periods after 2022. (1) Notwithstanding any other provision 
of this subpart, part 52 of this chapter, or any SIP revision approved 
under Sec.  52.38(b) of this chapter, the provisions of this paragraph 
and paragraphs (e)(2) through (7) of this section shall apply with 
regard to each CSAPR NOX Ozone Season Group 2 allowance that 
was allocated for a control period after 2022 to any unit (including a 
permanently retired unit qualifying for an exemption under Sec.  
97.805) in a State listed in Sec.  52.38(b)(2)(ii)(C) of this chapter 
(and Indian country within the borders of such a State) and that was 
initially recorded in the compliance account for the source that 
includes the unit, whether such CSAPR NOX Ozone Season Group 
2 allowance was allocated pursuant to this subpart or pursuant to a SIP 
revision approved under Sec.  52.38(b) of this chapter and whether such 
CSAPR NOX Ozone Season Group 2 allowance remains in such 
compliance account or has been transferred to another Allowance 
Management System account.
    (2)(i) For each CSAPR NOX Ozone Season Group 2 allowance 
described in paragraph (e)(1) of this section that was allocated for a 
given control period and initially recorded in a given source's 
compliance account, one CSAPR NOX Ozone Season Group 2 
allowance that was allocated for the same or an earlier control period 
and initially recorded in the same or any other Allowance Management 
System account must be surrendered in accordance with the procedures in 
paragraphs (e)(3) and (4) of this section.
    (ii)(A) The surrender requirement under paragraph (e)(2)(i) of this 
section corresponding to each CSAPR NOX Ozone Season Group 2 
allowance described in paragraph (e)(1) of this section initially 
recorded in a given source's compliance account shall apply to such 
source's current owners and operators, except as provided in paragraph 
(e)(2)(ii)(B) of this section.
    (B) If the owners and operators of a given source as of a given 
date assumed ownership and operational control of the source through a 
transaction that did not also provide rights to direct the use or 
transfer of a given CSAPR NOX Ozone Season Group 2 allowance 
described in paragraph (e)(1) of this section with regard to such 
source (whether recordation of such CSAPR NOX Ozone Season 
Group 2 allowance in the source's compliance account occurred before 
such transaction or was anticipated to occur after such transaction), 
then the surrender

[[Page 20202]]

requirement under paragraph (e)(2)(i) of this section corresponding to 
such CSAPR NOX Ozone Season Group 2 allowance shall apply to 
the most recent former owners and operators of the source before the 
occurrence of such a transaction.
    (C) The Administrator will not adjudicate any private legal dispute 
among the owners and operators of a source or among the former owners 
and operators of a source, including any disputes relating to the 
requirements to surrender CSAPR NOX Ozone Season Group 2 
allowances for the source under paragraph (e)(2)(i) of this section.
    (3)(i) As soon as practicable on or after [EFFECTIVE DATE OF FINAL 
RULE], the Administrator will send a notification to the designated 
representative for each source described in paragraph (e)(1) of this 
section identifying the amounts of CSAPR NOX Ozone Season 
Group 2 allowances allocated for each control period after 2022 and 
recorded in the source's compliance account and the corresponding 
surrender requirements for the source under paragraph (e)(2)(i) of this 
section.
    (ii) As soon as practicable on or after [15 DAYS AFTER EFFECTIVE 
DATE OF FINAL RULE], the Administrator will deduct from the compliance 
account for each source described in paragraph (e)(1) of this section 
CSAPR NOX Ozone Season Group 2 allowances eligible to 
satisfy the surrender requirements for the source under paragraph 
(e)(2)(i) of this section until all such surrender requirements for the 
source are satisfied or until no more CSAPR NOX Ozone Season 
Group 2 allowances eligible to satisfy such surrender requirements 
remain in such compliance account.
    (iii) As soon as practicable after completion of the deductions 
under paragraph (e)(3)(ii) of this section, the Administrator will 
identify for each source described in paragraph (e)(1) of this section 
the amounts, if any, of CSAPR NOX Ozone Season Group 2 
allowances allocated for each control period after 2022 and recorded in 
the source's compliance account for which the corresponding surrender 
requirements under paragraph (e)(2)(i) of this section have not been 
satisfied and will send a notification concerning such identified 
amounts to the designated representative for the source.
    (iv) With regard to each source for which unsatisfied surrender 
requirements under paragraph (e)(2)(i) of this section remain after the 
deductions under paragraph (e)(3)(ii) of this section:
    (A) Except as provided in paragraph (e)(3)(iv)(B) of this section, 
not later than September 15, 2023, the owners and operators of the 
source shall hold sufficient CSAPR NOX Ozone Season Group 2 
allowances eligible to satisfy such unsatisfied surrender requirements 
under paragraph (e)(2)(i) of this section in the source's compliance 
account.
    (B) With regard to any portion of such unsatisfied surrender 
requirements that apply to former owners and operators of the source 
pursuant to paragraph (e)(2)(ii)(B) of this section, not later than 
September 15, 2023, such former owners and operators shall hold 
sufficient CSAPR NOX Ozone Season Group 2 allowances 
eligible to satisfy such portion of the unsatisfied surrender 
requirements under paragraph (e)(2)(i) of this section either in the 
source's compliance account or in another Allowance Management System 
account identified to the Administrator on or before such date in a 
submission by the authorized account representative for such account.
    (C) As soon as practicable on or after September 15, 2023, the 
Administrator will deduct from the Allowance Management System account 
identified in accordance with paragraph (e)(3)(iv)(A) or (B) of this 
section CSAPR NOX Ozone Season Group 2 allowances eligible 
to satisfy the surrender requirements for the source under paragraph 
(e)(2)(i) of this section until all such surrender requirements for the 
source are satisfied or until no more CSAPR NOX Ozone Season 
Group 2 allowances eligible to satisfy such surrender requirements 
remain in such account.
    (v) When making deductions under paragraph (e)(3)(ii) or (iv) of 
this section to address the surrender requirements under paragraph 
(e)(2)(i) of this section for a given source:
    (A) The Administrator will make deductions to address any surrender 
requirements with regard to first the 2023 control period and then the 
2024 control period.
    (B) When making deductions to address the surrender requirements 
with regard to a given control period, the Administrator will first 
deduct CSAPR NOX Ozone Season Group 2 allowances allocated 
for such given control period and will then deduct CSAPR NOX 
Ozone Season Group 2 allowances allocated for each successively earlier 
control period in sequence.
    (C) When deducting CSAPR NOX Ozone Season Group 2 
allowances allocated for a given control period from a given Allowance 
Management System account, the Administrator will first deduct CSAPR 
NOX Ozone Season Group 2 allowances initially recorded in 
the account under Sec.  97.821 (if the account is a compliance account) 
in the order of recordation and will then deduct CSAPR NOX 
Ozone Season Group 2 allowances recorded in the account under Sec.  
97.526(d) or Sec.  97.823 in the order of recordation.
    (4)(i) To the extent the surrender requirements under paragraph 
(e)(2)(i) of this section corresponding to any CSAPR NOX 
Ozone Season Group 2 allowances allocated for a control period after 
2022 and initially recorded in a given source's compliance account have 
not been fully satisfied through the deductions under paragraph (e)(3) 
of this section, as soon as practicable on or after November 15, 2023, 
the Administrator will deduct such initially recorded CSAPR 
NOX Ozone Season Group 2 allowances from any Allowance 
Management System accounts in which such CSAPR NOX Ozone 
Season Group 2 allowances are held, making such deductions in any order 
determined by the Administrator, until all such surrender requirements 
for such source have been satisfied or until all such CSAPR 
NOX Ozone Season Group 2 allowances have been deducted, 
except as provided in paragraph (e)(4)(ii) of this section.
    (ii) If no person with an ownership interest in a given CSAPR 
NOX Ozone Season Group 2 allowance as of April 30, 2022, was 
an owner or operator of the source in whose compliance account such 
CSAPR NOX Ozone Season Group 2 allowance was initially 
recorded, was a direct or indirect parent or subsidiary of an owner or 
operator of such source, or was directly or indirectly under common 
ownership with an owner or operator of such source, the Administrator 
will not deduct such CSAPR NOX Ozone Season Group 2 
allowance under paragraph (e)(4)(i) of this section. For purposes of 
this paragraph, each owner or operator of a source shall be deemed to 
be a person with an ownership interest in any CSAPR NOX 
Ozone Season Group 2 allowance held in that source's compliance 
account. The limitation established by this paragraph on the 
deductibility of certain CSAPR NOX Ozone Season Group 2 
allowances under paragraph (e)(4)(i) of this section shall not be 
construed as a waiver of the surrender requirements under paragraph 
(e)(2)(i) of this section corresponding to such CSAPR NOX 
Ozone Season Group 2 allowances.
    (iii) Not less than 45 days before the planned date for any 
deductions under paragraph (e)(4)(i) of this section, the Administrator 
will send a notification to the authorized account representative for 
the Allowance Management System account from which such deductions

[[Page 20203]]

will be made identifying the CSAPR NOX Ozone Season Group 2 
allowances to be deducted and the data upon which the Administrator has 
relied and specifying a process for submission of any objections to 
such data. Any objections must be submitted to the Administrator not 
later than 15 days before the planned date for such deductions as 
indicated in such notification.
    (5) To the extent the surrender requirements under paragraph 
(e)(2)(i) of this section corresponding to any CSAPR NOX 
Ozone Season Group 2 allowances allocated for a control period after 
2022 and initially recorded in a given source's compliance account have 
not been fully satisfied through the deductions under paragraphs (e)(3) 
and (4) of this section:
    (i) The persons identified in accordance with paragraph (e)(2)(ii) 
of this section with regard to such source and each such CSAPR 
NOX Ozone Season Group 2 allowance shall pay any fine, 
penalty, or assessment or comply with any other remedy imposed under 
the Clean Air Act; and
    (ii) Each such CSAPR NOX Ozone Season Group 2 allowance, 
and each day in such control period, shall constitute a separate 
violation of this subpart and the Clean Air Act.
    (6) The Administrator will record in the appropriate Allowance 
Management System accounts all deductions of CSAPR NOX Ozone 
Season Group 2 allowances under paragraphs (e)(3) and (4) of this 
section.
    (7)(i) Each submission, objection, or other written communication 
from a designated representative, authorized account representative, or 
other person to the Administrator under paragraph (e)(2), (3), or (4) 
of this section shall be sent electronically to the email address 
[email protected]. Each such communication from a designated representative 
must contain the certification statement set forth in Sec.  97.814(a), 
and each such communication from the authorized account representative 
for a general account must contain the certification statement set 
forth in Sec.  97.820(c)(2)(ii).
    (ii) Each notification from the Administrator to a designated 
representative or authorized account representative under paragraph 
(e)(3) or (4) of this section will be sent electronically to the email 
address most recently received by the Administrator for such 
representative. In any such notification, the Administrator may provide 
information by means of a reference to a publicly accessible website 
where the information is available.


Sec.  97.812   [Amended]

0
64. Amend Sec.  97.812 by:
0
a. In paragraph (a) introductory text, removing ``State, the 
Administrator'' and adding in its place ``State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority, the Administrator'';
0
b. In paragraphs (a)(3)(iii) and (a)(5), adding ``and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority'' after ``in the State'';
0
c. In paragraph (a)(10), removing ``State, is allocated'' and adding in 
its place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority, is allocated'';
0
d. In paragraph (b) introductory text, removing ``Indian country within 
the borders of each State, the Administrator'' and adding in its place 
``areas of Indian country within the borders of each State not subject 
to the State's SIP authority, the Administrator''; and
0
e. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority''.


Sec.  97.821   [Amended]

0
65. In Sec.  97.821, amend paragraph (f) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.


Sec.  97.825   [Amended]

0
66. In Sec.  97.825, amend paragraphs (a) introductory text, (a)(2), 
(b)(1)(i), (b)(1)(ii)(A) and (B), (b)(3), (b)(4)(i), (b)(5), (b)(6)(i), 
(b)(6)(iii) introductory text, and (b)(6)(iii)(A) and (B) by removing 
``base CSAPR'' and adding in its place ``CSAPR'' each time it appears.
0
67. Amend Sec.  97.826 by:
0
a. In paragraph (b), removing ``(c) or (d)'' and adding in its place 
``(c), (d), or (e)'';
0
b. In paragraph (c), removing ``State (or Indian'' and adding in its 
place ``State (and Indian'';
0
c. In paragraphs (d)(1)(i)(A) and (B), removing ``Sec.  
52.38(b)(2)(iv)'' and adding in its place ``Sec.  52.38(b)(2)(ii)(B)'';
0
d. Revising paragraph (d)(1)(i)(C);
0
e. In paragraph (d)(1)(ii) introductory text, removing ``Sec.  
52.38(b)(2)(v)'' and adding in its place ``Sec.  52.38(b)(2)(iii)'';
0
f. Removing and reserving paragraph (d)(1)(iii);
0
g. Revising paragraph (d)(1)(iv) introductory text;
0
h. In paragraphs (d)(1)(iv)(A) and (B), removing ``or (d)(1)(iii)(C)'';
0
i. In paragraphs (d)(2)(i) and (d)(3), removing ``Sec.  52.38(b)(2)(v) 
of this chapter (or'' and adding in its place ``Sec.  52.38(b)(2)(iii) 
of this chapter (and'';
0
j. Redesignating paragraph (e) as paragraph (f) and adding a new 
paragraph (e);
0
k. Revising newly redesignated paragraphs (f)(1) and (2); and
0
l. Adding paragraph (f)(3).
    The revisions and additions read as follows:


Sec.  97.826   Banking and conversion.

* * * * *
    (d) * * *
    (1) * * *
    (i) * * *
    (C) The full-season CSAPR NOX Ozone Season Group 3 
allowance bank target, computed as the sum for all States listed in 
Sec.  52.38(b)(2)(iii)(A) of this chapter of the variability limits 
under Sec.  97.1010(e) for such States for the control period in 2022.
* * * * *
    (iv) For the compliance account of each source to which an amount 
of CSAPR NOX Ozone Season Group 3 allowances greater than 
zero is allocated under paragraph (d)(1)(ii)(C) of this section:
* * * * *
    (e) Notwithstanding any other provision of this subpart, part 52 of 
this chapter, or any SIP revision approved under Sec.  52.38(b)(8) or 
(9) of this chapter:
    (1) By [45 DAYS AFTER EFFECTIVE DATE OF FINAL RULE], the 
Administrator will temporarily suspend acceptance of CSAPR 
NOX Ozone Season Group 2 allowance transfers submitted under 
Sec.  97.822 and, before resuming acceptance of such transfers, will 
take the following actions with regard to every general account and 
every compliance account except a compliance account for a CSAPR 
NOX Ozone Season Group 2 source in a State listed in Sec.  
52.38(b)(2)(ii)(A) of this chapter (and Indian country within the 
borders of such a State):
    (i) The Administrator will deduct all CSAPR NOX Ozone 
Season Group 2 allowances allocated for the control periods in 2017 
through 2022 from each such account.
    (ii) The Administrator will determine a conversion factor equal to 
the greater of 1.0000 or the quotient, expressed to four decimal 
places, of the sum of all CSAPR NOX Ozone Season Group 2 
allowances deducted from all such accounts under paragraph (e)(1)(i) of 
this section divided by the sum of the variability limits for the 
control period in 2024 under Sec.  97.1010(e) for all States listed in 
Sec.  52.38(b)(2)(iii)(B) of this chapter.
    (iii) The Administrator will allocate and record in each such 
account an

[[Page 20204]]

amount of CSAPR NOX Ozone Season Group 3 allowances for the 
control period in 2023 computed as the quotient, rounded up to the 
nearest allowance, of the number of CSAPR NOX Ozone Season 
Group 2 allowances deducted from such account under paragraph (e)(1)(i) 
of this section divided by the conversion factor determined under 
paragraph (e)(1)(ii) of this section, except as provided in paragraph 
(e)(1)(iv) or (v) of this section.
    (iv) Where, pursuant to paragraph (e)(1)(i) of this section, the 
Administrator deducts CSAPR NOX Ozone Season Group 2 
allowances from the compliance account for a source in a State not 
listed in Sec.  52.38(b)(2)(iii) of this chapter (and Indian country 
within the borders of such a State), the Administrator will not record 
CSAPR NOX Ozone Season Group 3 allowances in that compliance 
account but instead will allocate and record the amount of CSAPR 
NOX Ozone Season Group 3 allowances for the control period 
in 2023 computed for such source in accordance with paragraph 
(e)(1)(iii) of this section in a general account identified by the 
designated representative for such source, provided that if the 
designated representative fails to identify such a general account in a 
submission to the Administrator by [45 DAYS AFTER EFFECTIVE DATE OF 
FINAL RULE], the Administrator may record such CSAPR NOX 
Ozone Season Group 3 allowances in a general account identified or 
established by the Administrator with the designated representative as 
the authorized account representative and with the owners and operators 
of such source (as indicated on the certificate of representation for 
the source) as the persons represented by the authorized account 
representative.
    (v)(A) In computing any amounts of CSAPR NOX Ozone 
Season Group 3 allowances to be allocated to and recorded in general 
accounts under paragraph (e)(1)(iii) of this section, the Administrator 
may group multiple general accounts whose ownership interests are held 
by the same or related persons or entities and treat the group of 
accounts as a single account for purposes of such computation.
    (B) Following a computation for a group of general accounts in 
accordance with paragraph (e)(1)(v)(A) of this section, the 
Administrator will allocate to and record in each individual account in 
such group a proportional share of the quantity of CSAPR NOX 
Ozone Season Group 3 allowances computed for such group, basing such 
shares on the respective quantities of CSAPR NOX Ozone 
Season Group 2 allowances removed from such individual accounts under 
paragraph (e)(1)(i) of this section.
    (C) In determining the proportional shares under paragraph 
(e)(1)(v)(B) of this section, the Administrator may employ any 
reasonable adjustment methodology to truncate or round each such share 
up or down to a whole number and to cause the total of such whole 
numbers to equal the amount of CSAPR NOX Ozone Season Group 
3 allowances computed for such group of accounts in accordance with 
paragraph (e)(1)(v)(A) of this section, even where such adjustments 
cause the numbers of CSAPR NOX Ozone Season Group 3 
allowances allocated to some individual accounts to equal zero.
    (2) After the Administrator has carried out the procedures set 
forth in paragraph (e)(1) of this section, upon any determination that 
would otherwise result in the initial recordation of a given number of 
CSAPR NOX Ozone Season Group 2 allowances in the compliance 
account for a source in a State listed in Sec.  52.38(b)(2)(iii)(B) of 
this chapter (and Indian country within the borders of such a State), 
the Administrator will not record such CSAPR NOX Ozone 
Season Group 2 allowances but instead will allocate and record in such 
account an amount of CSAPR NOX Ozone Season Group 3 
allowances for the control period in 2023 computed as the quotient, 
rounded up to the nearest allowance, of such given number of CSAPR 
NOX Ozone Season Group 2 allowances divided by the 
conversion factor determined under paragraph (e)(1)(ii) of this 
section.
    (f) * * *
    (1) Except as provided in paragraph (f)(3) of this section, after 
the Administrator has carried out the procedures set forth in paragraph 
(d)(1) of this section, the owner or operator of a CSAPR NOX 
Ozone Season Group 2 source in a State listed in Sec.  
52.38(b)(2)(iii)(A) of this chapter (and Indian country within the 
borders of such a State) may satisfy a requirement to hold a given 
number of CSAPR NOX Ozone Season Group 2 allowances for the 
control period in a year from 2017 through 2020 by holding instead, in 
a general account established for this sole purpose, an amount of CSAPR 
NOX Ozone Season Group 3 allowances for the control period 
in 2021 (or any later control period for which the allowance transfer 
deadline defined in Sec.  97.1002 has passed) computed as the quotient, 
rounded up to the nearest allowance, of such given number of CSAPR 
NOX Ozone Season Group 2 allowances divided by the 
conversion factor determined under paragraph (d)(1)(i)(D) of this 
section.
    (2) Except as provided in paragraph (f)(3) of this section, after 
the Administrator has carried out the procedures set forth in paragraph 
(e)(1) of this section, the owner or operator of a CSAPR NOX 
Ozone Season Group 2 source in a State listed in Sec.  
52.38(b)(2)(iii)(B) of this chapter (and Indian country within the 
borders of such a State) may satisfy a requirement to hold a given 
number of CSAPR NOX Ozone Season Group 2 allowances for the 
control period in a year from 2017 through 2022 by holding instead, in 
a general account established for this sole purpose, an amount of CSAPR 
NOX Ozone Season Group 3 allowances for the control period 
in 2023 (or any later control period for which the allowance transfer 
deadline defined in Sec.  97.1002 has passed) computed as the quotient, 
rounded up to the nearest allowance, of such given number of CSAPR 
NOX Ozone Season Group 2 allowances divided by the 
conversion factor determined under paragraph (e)(1)(ii) of this 
section.
    (3) CSAPR NOX Ozone Season Group 3 allowances may not be 
used to satisfy requirements to surrender CSAPR NOX Ozone 
Season Group 2 allowances under Sec.  97.811(d) or (e).

Subpart FFFFF--Texas SO2 Trading Program

0
68. Amend Sec.  97.902 by:
0
a. In the definition of ``alternate designated representative'', 
removing ``Program or CSAPR NOX Ozone Season Group 2 Trading 
Program, then'' and adding in its place ``Program, CSAPR NOX 
Ozone Season Group 2 Trading Program, or CSAPR NOX Ozone 
Season Group 3 Trading Program, then'';
0
b. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
c. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 3 Trading Program''; and
0
d. In the definition of ``designated representative'', removing 
``Program or CSAPR NOX Ozone Season Group 2 Trading Program, 
then'' and adding in its place ``Program, CSAPR NOX Ozone 
Season Group 2 Trading Program, or CSAPR NOX Ozone Season 
Group 3 Trading Program, then''.
    The addition reads as follows:


Sec.  97.902   Definitions.

* * * * *
    CSAPR NOX Ozone Season Group 3 Trading Program means a multi-state

[[Page 20205]]

NOX air pollution control and emission reduction program 
established in accordance with subpart GGGGG of this part and Sec.  
52.38(b)(1), (b)(2)(iii), and (b)(10) through (14) and (17) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(b)(10) or (11) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(b)(12) of this chapter), as a means of 
mitigating interstate transport of ozone and NOX.
* * * * *


Sec.  97.921   [Amended]

0
69. In Sec.  97.921, amend paragraph (b)(2) by removing ``2022'' and 
adding in its place ``2024'', and removing ``third'' before ``year 
after the year''.


Sec.  97.934   [Amended]

0
70. In Sec.  97.934, amend paragraph (d)(3) by removing ``Program or 
CSAPR NOX Ozone Season Group 2 Trading Program, quarterly'' 
and adding in its place ``Program, CSAPR NOX Ozone Season 
Group 2 Trading Program, or CSAPR NOX Ozone Season Group 3 
Trading Program, quarterly''.

Subpart GGGGG--CSAPR NOX Ozone Season Group 3 Trading Program

0
71. Amend Sec.  97.1002 by:
0
a. Revising the definition of ``allocate or allocation'';
0
b. In the definition of ``allowance transfer deadline'', adding 
``primary'' before ``emissions limitation'';
0
c. In the definition of ``alternate designated representative'', 
removing ``or CSAPR SO2 Group 1 Trading Program, then'' and 
adding in its place ``CSAPR SO2 Group 1 Trading Program, or 
CSAPR SO2 Group 2 Trading Program, then'';
0
d. Adding in alphabetical order a definition for ``backstop daily 
NOX emissions rate'';
0
e. In the definition of ``common designated representative's assurance 
level'', in paragraph (1), removing ``Sec.  97.1010(b)'' and adding in 
its place ``Sec.  97.1010(e)'', and revising paragraph (2);
0
f. In the definition of ``compliance account'', adding ``primary'' 
before ``emissions limitation'';
0
g. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 1 Trading Program'';
0
h. In the definition of ``CSAPR NOX Ozone Season Group 2 
Trading Program'', removing ``(b)(2)(iii) and (iv), and'' and adding in 
its place ``(b)(2)(ii), and'';
0
i. In the definition of ``CSAPR NOX Ozone Season Group 3 
allowance'', adding ``or (e)'' after ``Sec.  97.826(d)'', and adding 
``or less'' after ``one ton'';
0
j. In the definition of ``CSAPR NOX Ozone Season Group 3 
allowance deduction or deduct CSAPR NOX Ozone Season Group 3 
allowances'', adding ``primary'' before ``emissions limitation'';
0
k. In the definition of ``CSAPR NOX Ozone Season Group 3 
emissions limitation'', adding ``primary'' before ``emissions 
limitation'';
0
l. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 3 secondary emissions limitation'';
0
m. In the definition of ``CSAPR NOX Ozone Season Group 3 
Trading Program'', removing ``(b)(2)(v), and'' and adding in its place 
``(b)(2)(iii), and'';
0
n. Adding in alphabetical order a definition for ``CSAPR SO2 
Group 2 Trading Program'';
0
o. In the definition of ``designated representative'', removing ``or 
CSAPR SO2 Group 1 Trading Program, then'' and adding in its 
place ``CSAPR SO2 Group 1 Trading Program, or CSAPR 
SO2 Group 2 Trading Program, then''.
0
p. In the definition of ``excess emissions'', adding ``primary'' before 
``emissions limitation''; and
0
q. In the definition of ``State'', removing ``(b)(2)(v), and'' and 
adding in its place ``(b)(2)(iii), and''.
    The revisions and additions read as follows:


Sec.  97.1002  Definitions.

* * * * *
    Allocate or allocation means, with regard to CSAPR NOX 
Ozone Season Group 3 allowances, the determination by the 
Administrator, State, or permitting authority, in accordance with this 
subpart, Sec. Sec.  97.526(d) and 97.826(d) and (e), and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec.  52.38(b)(10), (11), or (12) of this chapter, of the amount of 
such CSAPR NOX Ozone Season Group 3 allowances to be 
initially credited, at no cost to the recipient, to:
    (1) A CSAPR NOX Ozone Season Group 3 unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside;
    (4) An Indian country existing unit set-aside; or
    (5) An entity not listed in paragraphs (1) through (4) of this 
definition;
    (6) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a CSAPR NOX Ozone Season 
Group 3 unit qualifying for an initial credit, a credit in the amount 
of zero CSAPR NOX Ozone Season Group 3 allowances, the CSAPR 
NOX Ozone Season Group 3 unit will be treated as being 
allocated an amount (i.e., zero) of CSAPR NOX Ozone Season 
Group 3 allowances.
* * * * *
    Backstop daily NOX emissions rate means an emissions 
rate limit used in the determination of the CSAPR NOX Ozone 
Season Group 3 primary emissions limitation for a CSAPR NOX 
Ozone Season Group 3 source in accordance with Sec.  97.1024(b).
* * * * *
    Common designated representative's assurance level * * *
    (2) Provided that the allocations of CSAPR NOX Ozone 
Season Group 3 allowances for any control period taken into account for 
purposes of this definition shall exclude any CSAPR NOX 
Ozone Season Group 3 allowances allocated for such control period under 
Sec.  97.526(d) or Sec.  97.826(d) or (e).
* * * * *
    CSAPR NOX Ozone Season Group 1 Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec.  
52.38(b)(1), (b)(2)(i), and (b)(3) through (5) and (13) through (15) of 
this chapter (including such a program that is revised in a SIP 
revision approved by the Administrator under Sec.  52.38(b)(3) or (4) 
of this chapter or that is established in a SIP revision approved by 
the Administrator under Sec.  52.38(b)(5) of this chapter), as a means 
of mitigating interstate transport of ozone and NOX.
* * * * *
    CSAPR NOX Ozone Season Group 3 secondary emissions limitation 
means, for a CSAPR NOX Ozone Season Group 3 unit to which 
such a limitation applies under Sec.  97.1025(c)(1) for a control 
period in a given year, the tonnage of NOX emissions 
calculated for the unit in accordance with Sec.  97.1025(c)(2) for such 
control period.
* * * * *
    CSAPR SO2 Group 2 Trading Program means a multi-state 
SO2 air pollution control and emission reduction program 
established in accordance with subpart DDDDD of this part and Sec.  
52.39(a), (c), (g) through (k), and (m) of this chapter (including such 
a program that is revised in a SIP revision approved by the 
Administrator under Sec.  52.39(g) or (h) of this chapter or that is 
established in a SIP revision approved by the Administrator under Sec.  
52.39(i) of this chapter), as a means of mitigating interstate 
transport of fine particulates and SO2.
* * * * *
0
72. Amend Sec.  97.1006 by:

[[Page 20206]]

0
a. Revising paragraph (b)(2), the paragraph (c)(1) heading, paragraph 
(c)(1)(i), and paragraph (c)(1)(ii) introductory text;
0
b. Adding paragraphs (c)(1)(iii) and (iv); and
0
c. Revising paragraphs (c)(2)(iii) and (c)(3).
    The revisions and additions read as follows:


Sec.  97.1006  Standard requirements.

* * * * *
    (b) * * *
    (2) The emissions and heat input data determined in accordance with 
Sec. Sec.  97.1030 through 97.1035 shall be used to calculate 
allocations of CSAPR NOX Ozone Season Group 3 allowances 
under Sec. Sec.  97.1011 and 97.1012 and to determine compliance with 
the CSAPR NOX Ozone Season Group 3 primary and secondary 
emissions limitations and assurance provisions under paragraph (c) of 
this section, provided that, for each monitoring location from which 
mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec.  97.1030 through 97.1035 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) * * *
    (1) CSAPR NOX Ozone Season Group 3 primary and secondary emissions 
limitations--(i) Primary emissions limitation. As of the allowance 
transfer deadline for a control period in a given year, the owners and 
operators of each CSAPR NOX Ozone Season Group 3 source and 
each CSAPR NOX Ozone Season Group 3 unit at the source shall 
hold, in the source's compliance account, CSAPR NOX Ozone 
Season Group 3 allowances available for deduction for such control 
period under Sec.  97.1024(a) in an amount not less than the amount 
determined under Sec.  97.1024(b), comprising the sum of:
    (A) The tons of total NOX emissions for such control 
period from all CSAPR NOX Ozone Season Group 3 units at the 
source; plus
    (B) Two times the sum, for all CSAPR NOX Ozone Season 
Group 3 units at the source and all days of the control period, of any 
NOX emissions from such a unit on any day of the control 
period exceeding the NOX emissions that would have occurred 
on that day if the unit had combusted the same daily heat input and 
emitted at any backstop daily NOX emissions rate applicable 
to the unit for that control period.
    (ii) Exceedances of primary emissions limitation. If total 
NOX emissions during a control period in a given year from 
the CSAPR NOX Ozone Season Group 3 units at a CSAPR 
NOX Ozone Season Group 3 source are in excess of the CSAPR 
NOX Ozone Season Group 3 primary emissions limitation set 
forth in paragraph (c)(1)(i) of this section, then:
* * * * *
    (iii) Secondary emissions limitation. The owner or operator of a 
base CSAPR NOX Ozone Season Group 3 unit subject to an 
emissions limitation under Sec.  97.1025(c)(1) shall not discharge, or 
allow to be discharged, emissions of NOX to the atmosphere 
during a control period in excess of the tonnage amount calculated in 
accordance with Sec.  97.1025(c)(2).
    (iv) Exceedances of secondary emissions limitation. If total 
NOX emissions during a control period in a given year from a 
base CSAPR NOX Ozone Season Group 3 unit are in excess of 
the amount of a CSAPR NOX Ozone Season Group 3 secondary 
emissions limitation applicable to the unit for the control period 
under paragraph (c)(1)(iii) of this section, then the owners and 
operators of the unit and the source at which the unit is located shall 
pay any fine, penalty, or assessment or comply with any other remedy 
imposed, for the same violations, under the Clean Air Act, and each ton 
of such excess emissions and each day of such control period shall 
constitute a separate violation of this subpart and the Clean Air Act.
    (2) * * *
    (iii) Total NOX emissions from all base CSAPR 
NOX Ozone Season Group 3 units at base CSAPR NOX 
Ozone Season Group 3 sources in a State (and Indian country within the 
borders of such State) during a control period in a given year exceed 
the State assurance level if such total NOX emissions exceed 
the sum, for such control period, of the State NOX Ozone 
Season Group 3 trading budget under Sec.  97.1010(a) and the State's 
variability limit under Sec.  97.1010(e).
* * * * *
    (3) Compliance periods.(i) A CSAPR NOX Ozone Season 
Group 3 unit shall be subject to the requirements under paragraphs 
(c)(1)(i) and (ii) of this section, and a base CSAPR NOX 
Ozone Season Group 3 unit shall be subject to the requirements under 
paragraph (c)(2) of this section, for the control period starting on 
the later of the applicable date in paragraph (c)(3)(i)(A), (B), or (C) 
of this section or the deadline for meeting the unit's monitor 
certification requirements under Sec.  97.1030(b) and for each control 
period thereafter:
    (A) May 1, 2021, for a unit in a State (and Indian country within 
the borders of such State) listed in Sec.  52.38(b)(2)(iii)(A) of this 
chapter;
    (B) May 1, 2023, for a unit in a State (and Indian country within 
the borders of such State) listed in Sec.  52.38(b)(2)(iii)(B) of this 
chapter; or
    (C) [EFFECTIVE DATE OF FINAL RULE], for a unit in a State (and 
Indian country within the borders of such State) listed in Sec.  
52.38(b)(2)(iii)(C) of this chapter.
    (ii) A base CSAPR NOX Ozone Season Group 3 unit shall be 
subject to the requirements under paragraphs (c)(1)(iii) and (iv) of 
this section for the control period starting on the later of May 1, 
2024 or the deadline for meeting the unit's monitor certification 
requirements under Sec.  97.1030(b) and for each control period 
thereafter.
* * * * *
0
73. Revise Sec.  97.1010 to read as follows:


Sec.  97.1010  State NOX Ozone Season Group 3 trading budgets, set-
asides, and variability limits.

    (a) State NOX Ozone Season Group 3 trading budgets. (1)(i) The 
State NOX Ozone Season Group 3 trading budgets for 
allocations of CSAPR NOX Ozone Season Group 3 allowances for 
the control periods in 2021, 2022, 2023, and 2024 are as indicated in 
Table 1 to this paragraph, subject to prorating for the control period 
in 2023 as provided in paragraph (a)(1)(ii) of this section:

[[Page 20207]]



        Table 1 to Paragraph (a)(1)(i)--State NOX Ozone Season Group 3 Trading Budgets by Control Period
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                                    Portion of
                                                                    Portion of     2023 control
                                                                   2023 control    period on and
                                                                   period before       after
              State                    2021            2022         [EFFECTIVE      [EFFECTIVE         2024
                                                                   DATE OF FINAL   DATE OF FINAL
                                                                   RULE], before   RULE], before
                                                                     prorating       prorating
----------------------------------------------------------------------------------------------------------------
Alabama.........................  ..............  ..............          13,211           6,364           6,306
Arkansas........................  ..............  ..............           9,210           8,889           8,889
Delaware........................  ..............  ..............  ..............             384             434
Illinois........................          11,223           9,102           8,179           7,364           7,463
Indiana.........................          17,004          12,582          12,553          11,151           9,391
Kentucky........................          17,542          14,051          14,051          11,640          11,640
Louisiana.......................          16,291          14,818          14,818           9,312           9,312
Maryland........................           2,397           1,266           1,266           1,187           1,187
Michigan........................          14,384          12,290           9,975          10,718          10,718
Minnesota.......................  ..............  ..............  ..............           3,921           3,921
Mississippi.....................  ..............  ..............           6,315           5,024           4,400
Missouri........................  ..............  ..............          15,780          11,857          11,857
Nevada..........................  ..............  ..............  ..............           2,280           2,372
New Jersey......................           1,565           1,253           1,253             799             799
New York........................           4,079           3,416           3,421           3,763           3,763
Ohio............................          13,481           9,773           9,773           8,369           8,369
Oklahoma........................  ..............  ..............          11,641          10,265           9,573
Pennsylvania....................          12,071           8,373           8,373           8,855           8,855
Tennessee.......................  ..............  ..............           7,736           4,234           4,234
Texas...........................  ..............  ..............          52,301          38,284          38,284
Utah............................  ..............  ..............  ..............          14,981          15,146
Virginia........................           6,331           3,897           3,980           3,090           2,814
West Virginia...................          15,062          12,884          12,884          12,478          12,478
Wisconsin.......................  ..............  ..............           7,915           5,963           5,057
Wyoming.........................  ..............  ..............  ..............           9,125           8,573
----------------------------------------------------------------------------------------------------------------

    (ii) For the control period in 2023, the State NOX Ozone 
Season Group 3 trading budget for each State shall be calculated as the 
sum of the following prorated amounts, rounded to the nearest 
allowance:
    (A) The product of the non-prorated trading budget for the portion 
of the 2023 control period before [EFFECTIVE DATE OF FINAL RULE] shown 
for the State in Table 1 to paragraph (a)(1)(i) of this section (or 
zero if Table 1 shows no amount for such portion of the 2023 control 
period for the State) multiplied by a fraction whose numerator is the 
number of days from May 1, 2023 through the day before [EFFECTIVE DATE 
OF FINAL RULE], inclusive, and whose denominator is 153; and
    (B) The product of the non-prorated trading budget for the portion 
of the 2023 control period on and after [EFFECTIVE DATE OF FINAL RULE] 
shown for the State in Table 1 to paragraph (a)(1)(i) of this section 
multiplied by a fraction whose numerator is the number of days from 
[EFFECTIVE DATE OF FINAL RULE] through September 30, 2023, inclusive, 
and whose denominator is 153.
    (2) The State NOX Ozone Season Group 3 trading budget 
for each State and each control period in 2025 and thereafter shall be 
the amount provided for the State and control period in the applicable 
notice of data availability issued under paragraph (a)(3)(v)(C) of this 
section.
    (3) The Administrator will calculate the State NOX Ozone 
Season Group 3 trading budget for each State and each control period in 
2025 and thereafter in the year before the year of the control period 
as follows:
    (i) The State's trading budget for the control period shall be 
calculated as the sum (converted to tons at a conversion factor of 
2,000 lb/ton and rounded to the nearest ton), for all units identified 
for inclusion in the calculation under paragraph (a)(3)(ii) of this 
section, of the product for each such unit of the NOX 
emissions rate in lb/mmBtu identified for the unit under paragraph 
(a)(3)(iii) of this section multiplied by the heat input in mmBtu 
identified for the unit under paragraph (a)(3)(iv) of this section.
    (ii) A unit in a State (and Indian country within the borders of 
the State) shall be included in the calculation of the State's trading 
budget for a control period if:
    (A) The unit was included in the calculation of the State's trading 
budget for the immediately preceding control period; or
    (B) The unit's deadline for certification of monitoring systems 
under Sec.  97.1030(b) is on or before May 1 of the year two years 
before the year of the control period (e.g., May 1, 2023 for 
calculation of the trading budget for the control period in 2025);
    (C) Provided that a unit shall not be included in the calculation 
of a State's trading budget for a control period if, before completing 
such calculation, the Administrator determines that the unit is not 
actually a CSAPR NOX Ozone Season Group 3 unit.
    (iii) For each unit included in the calculation of the State's 
trading budget for a control period, the NOX emissions rate 
in lb/mmBtu used in the calculation shall be identified as follows:
    (A) For a unit listed in the table entitled ``Dynamic Budget 2023 
Template'' and ``Dynamic Budget 2026+ Template'' posted at 
www.regulations.gov with docket identification number EPA-HQ-OAR-2021-
0668-[XXXX], the NOX emissions rate used in the calculation 
for the control period shall be the NOX emissions rate shown 
for the unit and control period in the tables.

[[Page 20208]]

    (B) For a unit not listed in the table referenced in paragraph 
(a)(3)(iii)(A) of this section, the NOX emissions rate used 
in the calculation for the control period shall be identified according 
to the type of unit and the type of fuel combusted by the unit during 
the control period beginning May 1 on or immediately after the unit's 
deadline for certification of monitoring systems under Sec.  97.1030(b) 
as follows:
    (1) 0.012 lb/mmBtu, for a combined cycle combustion turbine other 
than an integrated coal gasification combined cycle unit;
    (2) 0.030 lb/mmBtu, for a simple cycle combustion turbine or a 
boiler combusting only fuel oil or gaseous fuel (other than coal-
derived fuel) during such control period; or
    (3) 0.050 lb/mmBtu, for a boiler combusting any amount of coal or 
coal-derived fuel during such control period or any other unit not 
covered by paragraph (a)(3)(iii)(B)(1) or (2) of this section.
    (iv) For each unit included in the calculation of the State's 
trading budget for a control period, the heat input in mmBtu used in 
the calculation shall be identified as follows:
    (A) Except as provided in paragraph (a)(3)(iv)(B) of this section, 
the heat input used in the calculation for the control period shall be 
the heat input reported for the unit for the control period in the year 
two years before the year of the control period (e.g., heat input 
reported for the control period in 2023 shall be used in calculating 
the trading budget for the control period in 2025).
    (B) If no heat input data were reported for the unit for the 
control period in the year two years before the year of the control 
period and the heat input used for the unit in calculating the State's 
trading budget for the control period in 2024 was an estimate rather 
than the unit's actual reported heat input for the control period in 
2021 or an earlier year, the same estimated heat input used in 
calculating the State's trading budget for the control period in 2024 
shall be used in the calculations of the State's trading budgets for 
the control periods in 2025 and 2026.
    (v)(A) By March 1, 2024 and March 1 of each year thereafter, the 
Administrator will calculate the State CSAPR NOX Ozone 
Season Group 3 trading budget for each State, in accordance with 
paragraph (a)(3)(i) through (iv) of this section and Sec. Sec.  
97.1006(b)(2) and 97.1030 through 97.1035, for the control period in 
the year after the year of the applicable calculation deadline under 
this paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (B) For each notice of data availability required in paragraph 
(a)(3)(v)(A) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice. Objections shall be submitted by the deadline specified 
in such notice and shall be limited to addressing whether the 
calculations (including the identification of the units included in the 
calculations) are in accordance with the provisions referenced in 
paragraph (a)(3)(v)(A) of this section.
    (C) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (a)(3)(v)(A) of this section. By May 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (a)(3)(v)(A) of this section, the Administrator 
will promulgate a notice of data availability of the results of the 
calculations incorporating any adjustments that the Administrator 
determines to be necessary and the reasons for accepting or rejecting 
any objections submitted in accordance with paragraph (a)(3)(v)(B) of 
this section.
    (b) New unit set-asides. (1) The States' new unit set-asides for 
allocations of CSAPR NOX Ozone Season Group 3 allowances for 
the control periods in 2021, 2022, 2023, and 2024 are as indicated in 
Table 2 to this paragraph:

                       Table 2 to Paragraph (b)(1)--New Unit Set-Asides by Control Period
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                      State                            2021            2022            2023            2024
----------------------------------------------------------------------------------------------------------------
Alabama.........................................  ..............  ..............             191             189
Arkansas........................................  ..............  ..............             178             178
Delaware........................................  ..............  ..............              54              61
Illinois........................................             265             265             368             373
Indiana.........................................             262             254             223             188
Kentucky........................................             309             283             233             233
Louisiana.......................................             430             430             186             186
Maryland........................................             135             115              24              24
Michigan........................................             500             482             429             429
Minnesota.......................................  ..............  ..............              78              78
Mississippi.....................................  ..............  ..............             100              88
Missouri........................................  ..............  ..............             237             237
Nevada..........................................  ..............  ..............             137             142
New Jersey......................................              27              27              16              16
New York........................................             168             168             188             188
Ohio............................................             291             290             418             418
Oklahoma........................................  ..............  ..............             205             191
Pennsylvania....................................             335             339             266             266
Tennessee.......................................  ..............  ..............              85              85
Texas...........................................  ..............  ..............             766             766
Utah............................................  ..............  ..............             449             454
Virginia........................................             185             161             155             141
West Virginia...................................             266             261             250             250
Wisconsin.......................................  ..............  ..............             119             101
Wyoming.........................................  ..............  ..............             274             257
----------------------------------------------------------------------------------------------------------------


[[Page 20209]]

    (2) The new unit set-aside for allocations of CSAPR NOX 
Ozone Season Group 3 allowances for each State for each control period 
in 2025 and thereafter shall be calculated as the product (rounded to 
the nearest allowance) of the State NOX Ozone Season Group 3 
trading budget determined for the State and control period under 
paragraph (a)(2) of this section multiplied by 0.02.
    (c) Indian country new unit set-asides for the control periods in 
2021 and 2022. The States' Indian country new unit set-asides for 
allocations of CSAPR NOX Ozone Season Group 3 allowances for 
the control periods in 2021 and 2022 are as indicated in Table 3 to 
this paragraph:

 Table 3 to Paragraph (c)--Indian Country New Unit Set-Asides by Control
                                 Period
                                 [Tons]
------------------------------------------------------------------------
                       State                           2021       2022
------------------------------------------------------------------------
Alabama...........................................  .........  .........
Arkansas..........................................  .........  .........
Delaware..........................................  .........  .........
Illinois..........................................  .........  .........
Indiana...........................................  .........  .........
Kentucky..........................................  .........  .........
Louisiana.........................................         15         15
Maryland..........................................  .........  .........
Michigan..........................................         13         12
Minnesota.........................................  .........  .........
Mississippi.......................................  .........  .........
Missouri..........................................  .........  .........
Nevada............................................  .........  .........
New Jersey........................................  .........  .........
New York..........................................          3          3
Ohio..............................................  .........  .........
Oklahoma..........................................  .........  .........
Pennsylvania......................................  .........  .........
Tennessee.........................................  .........  .........
Texas.............................................  .........  .........
Utah..............................................  .........  .........
Virginia..........................................  .........  .........
West Virginia.....................................  .........  .........
Wisconsin.........................................  .........  .........
Wyoming...........................................  .........  .........
------------------------------------------------------------------------

    (d) Indian country existing unit set-asides for the control periods 
in 2023 and thereafter. The Indian country existing unit set-aside for 
allocations of CSAPR NOX Ozone Season Group 3 allowances for 
each State for each control period in 2023 and thereafter shall be 
calculated as the sum of all allowance allocations to units in areas of 
Indian country within the borders of the State not subject to the 
State's SIP authority as provided in the applicable notice of data 
availability for the control period referenced in Sec.  97.1011(a)(2).
    (e) Variability limits. (1) The variability limit for the State 
NOX Ozone Season Group 3 trading budget for each State for 
each control period from 2021 through 2024 shall be calculated as the 
product (rounded to the nearest ton) of the State NOX Ozone 
Season Group 3 trading budget determined for the State and control 
period in accordance with paragraph (a)(1) of this section multiplied 
by 0.21.
    (2) The variability limit for the State NOX Ozone Season 
Group 3 trading budget for each State for each control period in 2025 
and thereafter shall be calculated as the product (rounded to the 
nearest ton) of the State NOX Ozone Season Group 3 trading 
budget determined for the State and control period in accordance with 
paragraph (a)(2) of this section multiplied by the greater of:
    (i) 0.21; or
    (ii) Any excess over 1.00 of the quotient (rounded to two decimal 
places) of the total heat input reported for the control period for all 
CSAPR NOX Ozone Season Group 3 units in the State and Indian 
country within the borders of the State divided by the total heat input 
used in the calculation of the State's trading budget for the control 
period under paragraph (a)(3) of this section.
    (f) Relationship of trading budgets, set-asides, and variability 
limits. Each State NOX Ozone Season Group 3 trading budget 
in this section includes any tons in a new unit set-aside, Indian 
country new unit set-aside, or Indian country existing unit set-aside 
but does not include any tons in a variability limit.
0
74. Amend Sec.  97.1011 by revising the section heading and paragraphs 
(a), (b), and (c)(1) and (5) to read as follows:


Sec.  97.1011  CSAPR NOX Ozone Season Group 3 allowance allocations to 
existing units.

    (a) Allocations to existing units in general. (1) For the control 
periods in 2021 and each year thereafter, CSAPR NOX Ozone 
Season Group 3 allowances will be allocated to units in each State and 
areas of Indian country within the borders of the State subject to the 
State's SIP authority as provided in notices of data availability 
issued by the Administrator. Starting with the control period in 2025, 
the notices of data availability will be the notices issued under 
paragraph (b)(10)(iii) of this section.
    (2) For the control periods in 2023 and each year thereafter, CSAPR 
NOX Ozone Season Group 3 allowances will be allocated to 
units in areas of Indian country within the borders of each State not 
subject to the State's SIP authority as provided in notices of data 
availability issued by the Administrator. Starting with the control 
period in 2025, the notices of data availability will be the notices 
issued under paragraph (b)(10)(iii) of this section.
    (3) Providing an allocation to a unit in a notice of data 
availability does not constitute a determination that the unit is a 
CSAPR NOX Ozone Season Group 3 unit, and not providing an 
allocation to a unit in such notice does not constitute a determination 
that the unit is not a CSAPR NOX Ozone Season Group 3 unit.
    (b) Calculation of default allocations to existing units for 
control periods in 2025 and thereafter. For each control period in 2025 
and thereafter, and for the CSAPR NOX Ozone Season Group 3 
units in each State and areas of Indian country within the borders of 
the State, the Administrator will calculate default allocations of 
CSAPR NOX Ozone Season Group 3 allowances to the CSAPR 
NOX Ozone Season Group 3 units as follows:
    (1) For each State and control period, the total amount of CSAPR 
NOX Ozone Season Group 3 allowances for which default 
allocations will be calculated will be the remainder of the State 
NOX Ozone Season Group 3 trading budget for the control 
period under Sec.  97.1010(a)(2) minus the new unit set-aside for the 
control period under Sec.  97.1010(b)(2).
    (2) A default allocation of CSAPR NOX Ozone Season Group 
3 allowances will be calculated for a CSAPR NOX Ozone Season 
Group 3 unit in the State and Indian country within the borders of the 
State for a control period if:
    (i) The unit meets the conditions under Sec.  97.1010(a)(3)(ii) to 
be included in the calculation of the State's trading budget for the 
control period; and
    (ii) The unit reported heat input greater than zero for the control 
period in the year two years before the year of the control period.
    (3) For each CSAPR NOX Ozone Season Group 3 unit for 
which a default allocation is being calculated for a control period, 
the Administrator will determine the following amounts for the five-
year historical period ending with the year two years before the year 
of the control period for which default allocations are being 
calculated:
    (i) The total heat input reported for the unit in accordance with 
part 75 of this chapter for the control period in each year of the 
five-year historical period;
    (ii) The average of the three highest of the total heat input 
values determined for the unit under paragraph (b)(3)(i) of this 
section or, if fewer than three non-zero values were determined for the 
unit, the average of all such non-zero heat input values;

[[Page 20210]]

    (iii) The total NOX emissions reported for the unit in 
accordance with part 75 of this chapter for the control period in each 
year of the five-year historical period; and
    (iv) The maximum of the total NOX emissions values 
determined for the unit under paragraph (b)(3)(iii) of this section.
    (4) The Administrator will calculate the initial unrounded default 
allocations for each CSAPR NOX Ozone Season Group 3 unit 
according to the procedure in paragraph (b)(5) of this section and will 
recalculate the unrounded default allocations according to the 
procedures in paragraph (b)(6) or (7) of this section, as applicable, 
iterating the recalculations as necessary until the total of the 
unrounded default allocations to all eligible units equals the amount 
of allowances determined for the State under paragraph (b)(1) of this 
section.
    (5) The Administrator will calculate the initial unrounded default 
allocations to CSAPR NOX Ozone Season Group 3 units as 
follows:
    (i) The Administrator will calculate the sum, for all units 
determined under paragraph (b)(2) of this section to be eligible to 
receive a default allocation, of the units' average heat input 
determined under paragraph (b)(3)(ii) of this section.
    (ii) For each unit determined under paragraph (b)(2) of this 
section to be eligible to receive a default allocation, the 
Administrator will calculate the unit's unrounded default allocation as 
the lesser of:
    (A) The product of the total amount of allowances determined for 
the State and control period under paragraph (b)(1) of this section 
multiplied by a fraction whose numerator is the unit's average heat 
input determined under paragraph (b)(3)(ii) of this section and whose 
denominator is the sum determined under paragraph (b)(5)(i) of this 
section; and
    (B) The unit's maximum total NOX emissions determined 
under paragraph (b)(3)(iv) of this section.
    (iii) If the sum of the unrounded default allocations determined 
under paragraph (b)(5)(ii) of this section is less than the total 
amount of allowances determined for the State and control period under 
paragraph (b)(1) of this section, the Administrator will follow the 
procedures in paragraph (b)(6) or (7) of this section, as applicable.
    (iv) If the sum of the unrounded default allocations determined 
under paragraph (b)(5)(ii) of this section equals the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this section, the Administrator will determine the rounded 
default allocations according to the procedures in paragraphs (b)(8) 
and (9) of this section.
    (6) If the unrounded default allocation determined in the previous 
round of the calculation procedure for at least one CSAPR 
NOX Ozone Season Group 3 unit is less than the unit's 
maximum total NOX emissions determined under paragraph 
(b)(3)(iv) of this section, the Administrator will recalculate the 
unrounded default allocations as follows:
    (i) The Administrator will calculate the additional pool of 
allowances to be allocated as the remainder of the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this section minus the sum of the unrounded default 
allocations from the previous round of the calculation procedure for 
all units determined under paragraph (b)(2) of this section to be 
eligible to receive a default allocation.
    (ii) The Administrator will calculate the sum, for all units whose 
unrounded default allocations determined in the previous round of the 
calculation procedure were less than the respective units' maximum 
total NOX emissions determined under paragraph (b)(3)(iv) of 
this section, of the units' average heat input determined under 
paragraph (b)(3)(ii) of this section.
    (iii) For each unit whose unrounded default allocation determined 
in the previous round of the calculation was less than the unit's 
maximum total NOX emissions determined under paragraph 
(b)(3)(iv) of this section, the Administrator will recalculate the 
unit's unrounded default allocation, before rounding, as the lesser of:
    (A) The sum of the unit's unrounded default allocation determined 
in the previous round of the calculation procedure plus the product of 
the additional pool of allowances determined under paragraph (b)(6)(i) 
of this section multiplied by a fraction whose numerator is the unit's 
average heat input determined under paragraph (b)(3)(ii) of this 
section and whose denominator is the sum determined under paragraph 
(b)(6)(ii) of this section; and
    (B) The unit's maximum total NOX emissions determined 
under paragraph (b)(3)(iv) of this section.
    (iv) Except as provided in paragraph (b)(6)(iii) of this section, a 
unit's unrounded default allocation shall equal the amount determined 
in the previous round of the calculation procedure.
    (v) If the sum of the unrounded default allocations determined 
under paragraphs (b)(6)(iii) and (iv) of this section is less than the 
total amount of allowances determined for the State and control period 
under paragraph (b)(1) of this section, the Administrator will iterate 
the procedures in paragraph (b)(6) of this section or follow the 
procedures in paragraph (b)(7) of this section, as applicable.
    (vi) If the sum of the unrounded default allocations determined 
under paragraphs (b)(6)(iii) and (iv) of this section equals the total 
amount of allowances determined for the State and control period under 
paragraph (b)(1) of this section, the Administrator will determine the 
rounded default allocations according to the procedures in paragraphs 
(b)(8) and (9) of this section.
    (7) If the unrounded default allocation determined in the previous 
round of the calculation procedure for every CSAPR NOX Ozone 
Season Group 3 unit equals the unit's maximum total NOX 
emissions determined under paragraph (b)(3)(iv) of this section, the 
Administrator will recalculate the unrounded default allocations as 
follows:
    (i) The Administrator will calculate the additional pool of 
allowances to be allocated as the remainder of the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this section minus the sum of the unrounded default 
allocations from the previous round for all units determined under 
paragraph (b)(2) of this section to be eligible to receive a default 
allocation.
    (ii) The Administrator will recalculate the unrounded default 
allocation for each eligible unit as the sum of:
    (A) The unit's unrounded default allocation as determined in the 
previous round of the calculation procedure; plus
    (B) The product of the additional pool of allowances determined 
under paragraph (b)(7)(i) of this section multiplied by a fraction 
whose numerator is the unit's average heat input determined under 
paragraph (b)(3)(ii) of this section and whose denominator is the sum 
determined under paragraph (b)(5)(i) of this section.
    (8) The Administrator will round the default allocation for each 
eligible unit determined under paragraph (b)(5), (6), or (7) of this 
section to the nearest allowance and make any adjustments required 
under paragraph (b)(9) of this section.
    (9) If the sum of the default allocations after rounding under 
paragraph (b)(8) of this section does not equal the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this

[[Page 20211]]

section, the Administrator will adjust the default allocations as 
follows. The Administrator will list the CSAPR NOX Ozone 
Season Group 3 units in descending order based on such units' 
allocation amounts under paragraph (b)(8) of this section and, in cases 
of equal allocation amounts, in alphabetical order of the relevant 
sources' names and numerical order of the relevant units' 
identification numbers, and will adjust each unit's allocation amount 
upward or downward by one CSAPR NOX Ozone Season Group 3 
allowance (but not below zero) in the order in which the units are 
listed, and will repeat this adjustment process as necessary, until the 
total of the adjusted default allocations equals the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this section.
    (10)(i) By March 1, 2024 and March 1 of each year thereafter, the 
Administrator will calculate the default allocation of CSAPR 
NOX Ozone Season Group 3 allowances to each CSAPR 
NOX Ozone Season Group 3 unit in a State and Indian country 
within the borders of the State, in accordance with paragraphs (b)(1) 
through (9) of this section and Sec. Sec.  97.1006(b)(2) and 97.1030 
through 97.1035, for the control period in the year after the year of 
the applicable calculation deadline under this paragraph and will 
promulgate a notice of data availability of the results of the 
calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(10)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice. Objections shall be submitted by the deadline specified 
in such notice of data availability and shall be limited to addressing 
whether the calculations (including the identification of the CSAPR 
NOX Ozone Season Group 3 units) are in accordance with the 
provisions referenced in paragraph (b)(10)(i) of this section.
    (iii) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(10)(i) of this section. By May 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(10)(i) of this section, the Administrator 
will promulgate a notice of data availability of the results of the 
calculations incorporating any adjustments that the Administrator 
determines to be necessary and the reasons for accepting or rejecting 
any objections submitted in accordance with paragraph (b)(10)(ii) of 
this section.
    (c) Incorrect allocations of CSAPR NOX Ozone Season Group 3 
allowances to existing units. (1) For each control period in 2021 and 
thereafter, if the Administrator determines that CSAPR NOX 
Ozone Season Group 3 allowances were allocated for the control period 
to a recipient covered by the provisions of paragraph (c)(1)(i), (ii), 
or (iii) of this section, then the Administrator will notify the 
designated representative of the recipient and will act in accordance 
with the procedures set forth in paragraphs (c)(2) through (5) of this 
section:
    (i) The recipient is not actually a CSAPR NOX Ozone 
Season Group 3 unit under Sec.  97.1004 as of the first day of the 
control period and is allocated CSAPR NOX Ozone Season Group 
3 allowances for such control period under paragraph (a)(1) or (2) of 
this section;
    (ii) The recipient is not actually a CSAPR NOX Ozone 
Season Group 3 unit under Sec.  97.1004 as of the first day of the 
control period and is allocated CSAPR NOX Ozone Season Group 
3 allowances for such control period under a provision of a SIP 
revision approved under Sec.  52.38(b)(10), (11), or (12) of this 
chapter that the SIP revision provides should be allocated only to 
recipients that are CSAPR NOX Ozone Season Group 3 units as 
of the first day of such control period; or
    (iii) The recipient is not located as of the first day of the 
control period in the State (and Indian country within the borders of 
the State) from whose NOX Ozone Season Group 3 trading 
budget the CSAPR NOX Ozone Season Group 3 allowances 
allocated under paragraph (a)(1) or (2) of this section, or under a 
provision of a SIP revision approved under Sec.  52.38(b)(10), (11), or 
(12) of this chapter, were allocated for such control period.
* * * * *
    (5) With regard to any CSAPR NOX Ozone Season Group 3 
allowances that are not recorded, or that are deducted as an incorrect 
allocation, in accordance with paragraphs (c)(2) and (3) of this 
section:
    (i) If the non-recordation decision under paragraph (c)(2) of this 
section or the deduction under paragraph (c)(3) of this section occurs 
on or before May 1, 2024, the Administrator will transfer the CSAPR 
NOX Ozone Season Group 3 allowances to the new unit set-
aside for 2021, 2022, or 2023 for the State from whose NOX 
Ozone Season Group 3 trading budget the CSAPR NOX Ozone 
Season Group 3 allowances were allocated.
    (ii) If the non-recordation decision under paragraph (c)(2) of this 
section or the deduction under paragraph (c)(3) of this section occurs 
after May 1, 2024 and on or before May 1 of the year following the year 
of the control period for which the CSAPR NOX Ozone Season 
Group 3 allowances were allocated, the Administrator will transfer the 
CSAPR NOX Ozone Season Group 3 allowances to the new unit 
set-aside for such control period for the State from whose 
NOX Ozone Season Group 3 trading budget the CSAPR 
NOX Ozone Season Group 3 allowances were allocated.
    (iii) If the non-recordation decision under paragraph (c)(2) of 
this section or the deduction under paragraph (c)(3) of this section 
occurs after May 1, 2024 and after May 1 of the year following the year 
of the control period for which the CSAPR NOX Ozone Season 
Group 3 allowances were allocated, the Administrator will transfer the 
CSAPR NOX Ozone Season Group 3 allowances to a surrender 
account.
0
75. Amend Sec.  97.1012 by:
0
a. Revising paragraphs (a) introductory text and (a)(1)(i) and (ii);
0
b. Removing paragraphs (a)(1)(iii) and (iv);
0
c. Revising paragraphs (a)(2) and (a)(3)(i);
0
d. In paragraph (a)(3)(ii), adding ``and'' after the semicolon;
0
e. Revising paragraph (a)(3)(iii);
0
f. Removing paragraph (a)(3)(iv);
0
g. Revising paragraphs (a)(5) and (10):
0
h. In paragraph (a)(11), removing ``Sec.  97.1011(b)(1)(i), (ii), and 
(v), of'' and adding in its place ``paragraph (a)(13) of this section, 
of'';
0
i. Adding paragraph (a)(13);
0
j. Revising paragraphs (b) introductory text and (b)(1) and (2);
0
k. In paragraph (b)(5), removing ``Indian country within the borders of 
the State'' and adding in its place ``areas of Indian country within 
the borders of the State not subject to the State's SIP authority'';
0
l. Revising paragraph (b)(10);
0
m. In paragraph (b)(11), removing ``Sec.  97.1011(b)(2)(i), (ii), and 
(v), of'' and adding in its place ``paragraph (b)(13) of this section, 
of''; and
0
n. Adding paragraphs (b)(13) and (c).
    The revisions and additions read as follows:


Sec.  97.1012   CSAPR NOX Ozone Season Group 3 allowance allocations to 
new units.

    (a) Allocations from new unit set-asides. For each control period 
in 2021 and thereafter for a State listed in Sec.  52.38(b)(2)(iii)(A) 
of this chapter, or 2023 and thereafter for a State listed in Sec.  
52.38(b)(2)(iii)(B) or (C) of this chapter, and for the CSAPR 
NOX Ozone Season Group 3 units in each State and areas of

[[Page 20212]]

Indian country within the borders of the State (except, for the control 
periods in 2021 and 2022, areas of Indian country within the borders of 
the State not subject to the State's SIP authority), the Administrator 
will allocate CSAPR NOX Ozone Season Group 3 allowances to 
the CSAPR NOX Ozone Season Group 3 units as follows:
    (1) * * *
    (i) CSAPR NOX Ozone Season Group 3 units that are not 
allocated an amount of CSAPR NOX Ozone Season Group 3 
allowances for such control period in the applicable notice of data 
availability referenced in Sec.  97.1011(a)(1) or (2) and that have 
deadlines for certification of monitoring systems under Sec.  
97.1030(b) not later than September 30 of the year of the control 
period; or
    (ii) CSAPR NOX Ozone Season Group 3 units whose 
allocation of an amount of CSAPR NOX Ozone Season Group 3 
allowances for such control period in the applicable notice of data 
availability referenced in Sec.  97.1011(a)(1) or (2) is covered by 
Sec.  97.1011(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-
aside will be allocated CSAPR NOX Ozone Season Group 3 
allowances in an amount equal to the applicable amount of tons of 
NOX emissions as set forth in Sec.  97.1010(b) and will be 
allocated additional CSAPR NOX Ozone Season Group 3 
allowances (if any) in accordance with Sec.  97.1011(c)(5) and 
paragraphs (b)(10) and (c)(5) of this section.
    (3) * * *
    (i) The control period in 2021, for a State listed in Sec.  
52.38(b)(2)(iii)(A) of this chapter, or the control period in 2023, for 
a State listed in Sec.  52.38(b)(2)(iii)(B) or (C) of this chapter;
* * * * *
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the CSAPR NOX Ozone Season 
Group 3 unit operates in the State and Indian country within the 
borders of the State (except, for the control periods in 2021 and 2022, 
areas of Indian country within the borders of the State not subject to 
the State's SIP authority) after operating in another jurisdiction and 
for which the unit is not already allocated one or more CSAPR 
NOX Ozone Season Group 3 allowances.
* * * * *
    (5) The Administrator will calculate the sum of the allocation 
amounts of CSAPR NOX Ozone Season Group 3 allowances 
determined for all such CSAPR NOX Ozone Season Group 3 units 
under paragraph (a)(4)(i) of this section in the State and Indian 
country within the borders of the State (except, for the control 
periods in 2021 and 2022, areas of Indian country within the borders of 
the State not subject to the State's SIP authority) for such control 
period.
* * * * *
    (10)(i) For a control period in 2021 or 2022, if, after completion 
of the procedures under paragraphs (a)(2) through (7) and (12) of this 
section for a control period, any unallocated CSAPR NOX 
Ozone Season Group 3 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each CSAPR NOX Ozone Season Group 3 unit that is in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority and is allocated an amount of 
CSAPR NOX Ozone Season Group 3 allowances for the control 
period in the applicable notice of data availability referenced in 
Sec.  97.1011(a)(1) an amount of CSAPR NOX Ozone Season 
Group 3 allowances equal to the following: The total amount of such 
remaining unallocated CSAPR NOX Ozone Season Group 3 
allowances in such new unit set-aside, multiplied by the unit's 
allocation under Sec.  97.1011(a)(1) for such control period, divided 
by the remainder of the amount of tons in the applicable State 
NOX Ozone Season Group 3 trading budget minus the sum of the 
amounts of tons in such new unit set-aside and the Indian country new 
unit set-aside for the State for such control period, and rounded to 
the nearest allowance.
    (ii) For a control period in 2023 or thereafter, if, after 
completion of the procedures under paragraphs (a)(2) through (7) and 
(12) of this section for a control period, any unallocated CSAPR 
NOX Ozone Season Group 3 allowances remain in the new unit 
set-aside for the State for such control period, the Administrator will 
allocate to each CSAPR NOX Ozone Season Group 3 unit that is 
in the State and Indian country within the borders of the State and is 
allocated an amount of CSAPR NOX Ozone Season Group 3 
allowances for the control period by the Administrator in the 
applicable notice of data availability referenced in Sec.  
97.1011(a)(1) or (2), or under a provision of a SIP revision approved 
under Sec.  52.38(b)(10), (11), or (12) of this chapter, an amount of 
CSAPR NOX Ozone Season Group 3 allowances equal to the 
following: The total amount of such remaining unallocated CSAPR 
NOX Ozone Season Group 3 allowances in such new unit set-
aside, multiplied by the unit's allocation under Sec.  97.1011(a)(1) or 
(2) or a provision of a SIP revision approved under Sec.  52.38(b)(10), 
(11), or (12) of this chapter for such control period, divided by the 
remainder of the amount of tons in the applicable State NOX 
Ozone Season Group 3 trading budget minus the amount of tons in such 
new unit set-aside for the State for such control period, and rounded 
to the nearest allowance.
* * * * *
    (13)(i) By March 1, 2022 and March 1 of each year thereafter, the 
Administrator will calculate the CSAPR NOX Ozone Season 
Group 3 allowance allocation to each CSAPR NOX Ozone Season 
Group 3 unit in a State and Indian country within the borders of the 
State (except, for the control periods in 2021 and 2022, areas of 
Indian country within the State not subject to the State's SIP 
authority), in accordance with paragraphs (a)(2) through (7), (10), and 
(12) of this section and Sec. Sec.  97.1006(b)(2) and 97.1030 through 
97.1035, for the control period in the year before the year of the 
applicable calculation deadline under this paragraph and will 
promulgate a notice of data availability of the results of the 
calculations.
    (ii) For each notice of data availability required in paragraph 
(a)(13)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice. Objections shall be submitted by the deadline specified 
in such notice and shall be limited to addressing whether the 
calculations (including the identification of the CSAPR NOX 
Ozone Season Group 3 units) are in accordance with the provisions 
referenced in paragraph (a)(13)(i) of this section.
    (iii) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (a)(13)(i) of this section. By May 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (a)(13)(i) of this section, the Administrator 
will promulgate a notice of data availability of the results of the 
calculations incorporating any adjustments that the Administrator 
determines to be necessary and the reasons for accepting or rejecting 
any objections submitted in accordance with paragraph (a)(13)(ii) of 
this section.
    (b) Allocations from Indian country new unit set-asides. For the 
control periods in 2021 and 2022, for a State listed in Sec.  
52.38(b)(2)(iii)(A) of this chapter, and for the CSAPR NOX 
Ozone

[[Page 20213]]

Season Group 3 units in areas of Indian country within the borders of 
each such State not subject to the State's SIP authority, the 
Administrator will allocate CSAPR NOX Ozone Season Group 3 
allowances to the CSAPR NOX Ozone Season Group 3 units as 
follows:
    (1) The CSAPR NOX Ozone Season Group 3 allowances will 
be allocated to CSAPR NOX Ozone Season Group 3 units that 
are not allocated an amount of CSAPR NOX Ozone Season Group 
3 allowances for such control period in the applicable notice of data 
availability issued under Sec.  97.1011(a)(1) and that have deadlines 
for certification of monitoring systems under Sec.  97.1030(b) not 
later than September 30 of the year of the control period, except as 
provided in paragraph (b)(10) of this section.
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated CSAPR 
NOX Ozone Season Group 3 allowances in an amount equal to 
the applicable amount of tons of NOX emissions as set forth 
in Sec.  97.1010(c) and will be allocated additional CSAPR 
NOX Ozone Season Group 3 allowances (if any) in accordance 
with paragraph (c)(5) of this section.
* * * * *
    (10) If, after completion of the procedures under paragraphs (b)(2) 
through (7) and (12) of this section for a control period, any 
unallocated CSAPR NOX Ozone Season Group 3 allowances remain 
in the Indian country new unit set-aside for the State for such control 
period, the Administrator will transfer such unallocated CSAPR 
NOX Ozone Season Group 3 allowances to the new unit set-
aside for the State for such control period.
* * * * *
    (13)(i) By March 1, 2022 and March 1, 2023, the Administrator will 
calculate the CSAPR NOX Ozone Season Group 3 allowance 
allocation to each CSAPR NOX Ozone Season Group 3 unit in 
areas of Indian country within the borders of a State not subject to 
the State's SIP authority, in accordance with paragraphs (b)(2) through 
(7), (10), and (12) of this section and Sec. Sec.  97.1006(b)(2) and 
97.1030 through 97.1035, for the control period in the year before the 
year of the applicable calculation deadline under this paragraph and 
will promulgate a notice of data availability of the results of the 
calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(13)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice. Objections shall be submitted by the deadline specified 
in such notice and shall be limited to addressing whether the 
calculations (including the identification of the CSAPR NOX 
Ozone Season Group 3 units) are in accordance with the provisions 
referenced in paragraph (b)(13)(i) of this section.
    (iii) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(13)(i) of this section. By May 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(13)(i) of this section, the Administrator 
will promulgate a notice of data availability of the results of the 
calculations incorporating any adjustments that the Administrator 
determines to be necessary and the reasons for accepting or rejecting 
any objections submitted in accordance with paragraph (b)(13)(ii) of 
this section.
    (c) Incorrect allocations of CSAPR NOX Ozone Season Group 3 
allowances to new units. (1) For each control period in 2021 and 
thereafter, if the Administrator determines that CSAPR NOX 
Ozone Season Group 3 allowances were allocated for the control period 
under paragraphs (a)(2) through (7) and (12) of this section or 
paragraphs (b)(2) through (7) and (12) of this section to a recipient 
that is not actually a CSAPR NOX Ozone Season Group 3 unit 
under Sec.  97.1004 as of the first day of such control period, then 
the Administrator will notify the designated representative of the 
recipient and will act in accordance with the procedures set forth in 
paragraphs (c)(2) through (5) of this section.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such CSAPR NOX Ozone 
Season Group 3 allowances under Sec.  97.1021.
    (3) If the Administrator already recorded such CSAPR NOX 
Ozone Season Group 3 allowances under Sec.  97.1021 and if the 
Administrator makes the determination under paragraph (c)(1) of this 
section before making deductions for the source that includes such 
recipient under Sec.  97.1024(b) for such control period, then the 
Administrator will deduct from the account in which such CSAPR 
NOX Ozone Season Group 3 allowances were recorded an amount 
of CSAPR NOX Ozone Season Group 3 allowances allocated for 
the same or a prior control period equal to the amount of such already 
recorded CSAPR NOX Ozone Season Group 3 allowances. The 
authorized account representative shall ensure that there are 
sufficient CSAPR NOX Ozone Season Group 3 allowances in such 
account for completion of the deduction.
    (4) If the Administrator already recorded such CSAPR NOX 
Ozone Season Group 3 allowances under Sec.  97.1021 and if the 
Administrator makes the determination under paragraph (c)(1) of this 
section after making deductions for the source that includes such 
recipient under Sec.  97.1024(b) for such control period, then the 
Administrator will not make any deduction to take account of such 
already recorded CSAPR NOX Ozone Season Group 3 allowances.
    (5) With regard to any CSAPR NOX Ozone Season Group 3 
allowances that are not recorded, or that are deducted as an incorrect 
allocation, in accordance with paragraphs (c)(2) and (3) of this 
section:
    (i) If the non-recordation decision under paragraph (c)(2) of this 
section or the deduction under paragraph (c)(3) of this section occurs 
on or before May 1, 2023, the Administrator will transfer the CSAPR 
NOX Ozone Season Group 3 allowances to the new unit set-
aside, in the case of allowances allocated under paragraph (a) of this 
section, or the Indian country new unit set-aside, in the case of 
allowances allocated under paragraph (b) of this section, for the 
control period in 2021 or 2022 for the State from whose NOX 
Ozone Season Group 3 trading budget the CSAPR NOX Ozone 
Season Group 3 allowances were allocated.
    (ii) If the non-recordation decision under paragraph (c)(2) of this 
section or the deduction under paragraph (c)(3) of this section occurs 
after May 1, 2023 and on or before May 1, 2024, the Administrator will 
transfer the CSAPR NOX Ozone Season Group 3 allowances to 
the new unit set-aside for the control period in 2023 for the State 
from whose NOX Ozone Season Group 3 trading budget the CSAPR 
NOX Ozone Season Group 3 allowances were allocated.
    (iii) If the non-recordation decision under paragraph (c)(2) of 
this section or the deduction under paragraph (c)(3) of this section 
occurs after May 1, 2024, the Administrator will transfer the CSAPR 
NOX Ozone Season Group 3 allowances to a surrender account.
0
76. Amend Sec.  97.1021 by:
0
a. In paragraph (a), removing ``Sec.  97.1011(a)'' and adding in its 
place ``Sec.  97.1011(a)(1)'';
0
b. Revising paragraph (b);
0
c. Removing and reserving paragraph (c);
0
d. Revising paragraph (d);
0
e. Adding paragraph (e);
0
f. Revising paragraphs (f) and (g);

[[Page 20214]]

0
g. In paragraph (h), removing ``May 1 of each year thereafter, the'' 
and adding in its place ``May 1, 2023, the'';
0
h. Adding paragraphs (i) and (j); and
0
i. In paragraph (m), adding ``or (e)'' after ``Sec.  97.811(d)'' each 
time it appears.
    The revisions and addition read as follows:


Sec.  97.1021   Recordation of CSAPR NOX Ozone Season Group 3 allowance 
allocations and auction results.

* * * * *
    (b) By July 29, 2021, the Administrator will record in each CSAPR 
NOX Ozone Season Group 3 source's compliance account the 
CSAPR NOX Ozone Season Group 3 allowances allocated to the 
CSAPR NOX Ozone Season Group 3 units at the source in 
accordance with Sec.  97.1011(a)(1) for the control period in 2022.
* * * * *
    (d) By [30 DAYS AFTER EFFECTIVE DATE OF FINAL RULE], the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source in accordance with Sec.  
97.1011(a)(1) for the control period in 2023.
    (e) By [30 DAYS AFTER EFFECTIVE DATE OF FINAL RULE], the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source in accordance with Sec.  
97.1011(a)(1) for the control period in 2024, unless the State in which 
the source is located notifies the Administrator in writing by 
[EFFECTIVE DATE OF FINAL RULE] of the State's intent to submit to the 
Administrator a complete SIP revision by September 1, 2023 meeting the 
requirements of Sec.  52.38(b)(10)(i) through (iv) of this chapter.
    (1) If, by September 1, 2023 the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by September 15, 2023 in each CSAPR NOX Ozone Season Group 3 
source's compliance account the CSAPR NOX Ozone Season Group 
3 allowances allocated to the CSAPR NOX Ozone Season Group 3 
units at the source in accordance with Sec.  97.1011(a)(1) for the 
control period in 2024.
    (2) If the State submits to the Administrator by September 1, 2023 
and the Administrator approves by March 1, 2024 such complete SIP 
revision, the Administrator will record by March 1, 2024 in each CSAPR 
NOX Ozone Season Group 3 source's compliance account the 
CSAPR NOX Ozone Season Group 3 allowances allocated to the 
CSAPR NOX Ozone Season Group 3 units at the source as 
provided in such approved, complete SIP revision for the control period 
in 2024.
    (3) If the State submits to the Administrator by September 1, 2023 
and the Administrator does not approve by March 1, 2024 such complete 
SIP revision, the Administrator will record by March 1, 2024 in each 
CSAPR NOX Ozone Season Group 3 source's compliance account 
the CSAPR NOX Ozone Season Group 3 allowances allocated to 
the CSAPR NOX Ozone Season Group 3 units at the source in 
accordance with Sec.  97.1011(a)(1) for the control period in 2024.
    (f) By July 1, 2024 and July 1 of each year thereafter, the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source, or in each appropriate Allowance 
Management System account the CSAPR NOX Ozone Season Group 3 
allowances auctioned to CSAPR NOX Ozone Season Group 3 
units, in accordance with Sec.  97.1011(a)(1), or with a SIP revision 
approved under Sec.  52.38(b)(11) or (12) of this chapter, for the 
control period in the year after the year of the applicable recordation 
deadline under this paragraph.
    (g) By May 1, 2022 and May 1 of each year thereafter, the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source in accordance with Sec.  97.1012(a) 
for the control period in the year before the year of the applicable 
recordation deadline under this paragraph.
* * * * *
    (i) By [30 DAYS AFTER EFFECTIVE DATE OF FINAL RULE], the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source in accordance with Sec.  
97.1011(a)(2) for the control periods in 2023 and 2024.
    (j) By July 1, 2024 and July 1 of each year thereafter, the 
Administrator will record in each CSAPR NOX Ozone Season 
Group 3 source's compliance account the CSAPR NOX Ozone 
Season Group 3 allowances allocated to the CSAPR NOX Ozone 
Season Group 3 units at the source in accordance with Sec.  
97.1011(a)(2) for the control period in the year after the year of the 
applicable recordation deadline under this paragraph.
* * * * *
0
77. Amend Sec.  97.1024 by:
0
a. Revising the section heading;
0
b. In paragraphs (a) introductory text and (b) introductory text, 
adding ``primary'' before ``emissions limitation'';
0
c. Revising paragraph (b)(1);
0
d. Adding paragraph (b)(3); and
0
e. In paragraph (c)(2)(ii), adding ``or (e)'' after ``Sec.  
97.826(d)''.
    The revisions and addition read as follows:


Sec.  97.1024   Compliance with CSAPR NOX Ozone Season Group 3 primary 
emissions limitation.

* * * * *
    (b) * * *
    (1) Until the amount of CSAPR NOX Ozone Season Group 3 
allowances deducted equals the sum of:
    (i) The number of tons of total NOX emissions from all 
CSAPR NOX Ozone Season Group 3 units at the source for such 
control period; plus
    (ii) Two times the sum (converted to tons at a conversion factor of 
2,000 lb/ton and rounded to the nearest ton), for all days in the 
control period and all CSAPR NOX Ozone Season Group 3 units 
at the source to which backstop daily NOX emissions rates 
apply for the control period under paragraph (b)(3) of this section, of 
any amount by which a unit's NOX emissions for a given day 
in pounds exceed the product in pounds of the unit's total heat input 
in mmBtu for that day multiplied by the applicable backstop daily 
NOX emissions rate in lb/mmBtu; or
* * * * *
    (3) The applicable backstop daily NOX emissions rates 
are as follows:
    (i) For the control periods in 2024 and each year thereafter, a 
backstop daily NOX emissions rate of 0.14 lb/mmBtu shall 
apply to each CSAPR NOX Ozone Season Group 3 unit combusting 
any coal during the control period, serving a generator with nameplate 
capacity of 100 MW or more, and equipped with selective catalytic 
reduction controls, except a circulating fluidized bed boiler.
    (ii) For the control periods in 2027 and each year thereafter, a 
backstop daily NOX emissions rate of 0.14 lb/mmBtu shall 
apply to each CSAPR NOX Ozone Season Group 3 unit combusting 
any coal during the control period and serving a generator with 
nameplate

[[Page 20215]]

capacity of 100 MW or more, except a circulating fluidized bed boiler.
* * * * *
0
78. Amend Sec.  97.1025 by revising the section heading and adding 
paragraph (c) to read as follows:


Sec.  97.1025   Compliance with CSAPR NOX Ozone Season Group 3 
assurance provisions; CSAPR NOX Ozone Season Group 3 secondary 
emissions limitation.

* * * * *
    (c) CSAPR NOX Ozone Season Group 3 secondary emissions limitation. 
(1) The owner or operator of a base CSAPR NOX Ozone Season 
Group 3 unit shall not discharge, or allow to be discharged, emissions 
of NOX to the atmosphere during a control period in excess 
of the tonnage amount calculated in accordance with paragraph (c)(2) of 
this section, provided that the emissions limitation established under 
this paragraph shall apply to a unit for a control period only if:
    (i) The unit is included for the control period in a group of base 
CSAPR NOX Ozone Season Group 3 units at base CSAPR 
NOX Ozone Season Group 3 sources in a State (and Indian 
country within the borders of such State) having a common designated 
representative and the owners and operators of such units and sources 
are subject to a requirement for such control period to hold one or 
more CSAPR NOX Ozone Season Group 3 allowances under Sec.  
97.1006(c)(2)(i) and paragraph (b) of this section with respect to such 
group; and
    (ii) The unit was required to report NOX emissions and 
heat input data for all or portions of at least 367 operating hours 
during the control period and all or portions of at least 367 operating 
hours during at least one previous control period under the CSAPR 
NOX Ozone Season Group 1 Trading Program, CSAPR 
NOX Ozone Season Group 2 Trading Program, or CSAPR 
NOX Ozone Season Group 3 Trading Program.
    (2) The amount of the emissions limitation applicable to a base 
CSAPR NOX Ozone Season Group 3 unit for a control period 
under paragraph (c)(1) of this section, in tons of NOX, 
shall be calculated as the sum of 50 plus the product (converted to 
tons at a conversion factor of 2,000 lb/ton and rounded to the nearest 
ton) of multiplying--
    (i) The total heat input in mmBtu reported for the unit for the 
control period in accordance with Sec. Sec.  97.1030 through 97.1035; 
and
    (ii) A NOX emission rate of 0.10 lb/mmBtu or, if higher, 
the product of 1.25 times the lowest seasonal average NOX 
emission rate in lb/mmBtu achieved by the unit in any previous control 
period for which the unit was required to report NOX 
emissions and heat input data for all or portions of at least 367 
operating hours under the CSAPR NOX Ozone Season Group 1 
Trading Program, CSAPR NOX Ozone Season Group 2 Trading 
Program, or CSAPR NOX Ozone Season Group 3 Trading Program, 
where the unit's seasonal average NOX emission rate for each 
such previous control period shall be calculated from such reported 
data as the quotient of the unit's total NOX emissions in 
tons for the control period divided by the unit's total heat input in 
mmBtu for the control period, multiplied by a conversion factor of 
2,000 lb/ton, and rounded to the nearest 0.0001 lb/mmBtu.
0
79. Amend Sec.  97.1026 by:
0
a. Revising paragraph (b);
0
b. In paragraph (c), removing ``State (or Indian'' and adding in its 
place ``State (and Indian''; and
0
c. Adding paragraph (d).
    The revision and addition read as follows:


Sec.  97.1026   Banking.

* * * * *
    (b) Any CSAPR NOX Ozone Season Group 3 allowance that is 
held in a compliance account or a general account will remain in such 
account unless and until the CSAPR NOX Ozone Season Group 3 
allowance is deducted or transferred under Sec.  97.1011(c), Sec.  
97.1012(c), Sec.  97.1023, Sec.  97.1024, Sec.  97.1025, Sec.  97.1027, 
or Sec.  97.1028 or paragraph (c) or (d) of this section.
* * * * *
    (d) Before the allowance transfer deadline for each control period 
in 2024 or a subsequent year, the Administrator will deduct amounts of 
CSAPR NOX Ozone Season Group 3 allowances issued for the 
control periods in previous years exceeding the CSAPR NOX 
Ozone Season Group 3 allowance bank ceiling target for the control 
period in accordance with paragraphs (d)(1) through (4) of this 
section.
    (1) As soon as practicable on or after August 1, 2024 and August 1 
of each subsequent year, the Administrator will temporarily suspend 
acceptance of CSAPR NOX Ozone Season Group 3 allowance 
transfers submitted under Sec.  97.1022 and, before resuming acceptance 
of such transfers, will take the actions in paragraphs (d)(2) through 
(4) of this section.
    (2) The Administrator will determine each of the following values:
    (i) The CSAPR NOX Ozone Season Group 3 allowance bank 
ceiling target for the control period in the year of the deadline under 
paragraph (d)(1) of this section, calculated as the product, rounded to 
the nearest allowance, of 0.105 times the sum for all States listed in 
Sec.  52.38(b)(2)(iii) of this chapter of the State NOX 
Ozone Season Group 3 trading budgets under Sec.  97.1010(a) for such 
States for such control period.
    (ii) The total amount of CSAPR NOX Ozone Season Group 3 
allowances issued for control periods in years before the year of the 
deadline under paragraph (d)(1) of this section and held in all 
compliance and general accounts.
    (3) If the CSAPR NOX Ozone Season Group 3 allowance bank 
ceiling target determined under paragraph (d)(2)(i) of this section is 
less than the total amount of CSAPR NOX Ozone Season Group 3 
allowances determined under paragraph (d)(2)(ii) of this section, then 
for each compliance account or general account holding CSAPR 
NOX Ozone Season Group 3 allowances issued for control 
periods in years before the year of the deadline under paragraph (d)(1) 
of this section, the Administrator will:
    (i) Determine the total amount of CSAPR NOX Ozone Season 
Group 3 allowances issued for control periods in years before the year 
of the deadline under paragraph (d)(1) of this section and held in the 
account.
    (ii) Determine the account's share of the CSAPR NOX 
Ozone Season Group 3 allowance bank ceiling target for the control 
period, calculated as the product, rounded up to the nearest allowance, 
of the CSAPR NOX Ozone Season Group 3 allowance bank ceiling 
target determined under paragraph (d)(2)(i) of this section multiplied 
by a fraction whose numerator is the total amount of CSAPR 
NOX Ozone Season Group 3 allowances held in the account 
determined under paragraph (d)(3)(i) of this section and whose 
denominator is the total amount of CSAPR NOX Ozone Season 
Group 3 allowances held in all compliance and general accounts 
determined under paragraph (d)(2)(ii) of this section.
    (iii) Deduct an amount of CSAPR NOX Ozone Season Group 3 
allowances issued for control periods in years before the year of the 
deadline under paragraph (d)(1) of this section equal to any positive 
remainder of the total amount of CSAPR NOX Ozone Season 
Group 3 allowances held in the account determined under paragraph 
(d)(3)(i) of this section minus the account's share of the CSAPR 
NOX Ozone Season Group 3 allowance bank ceiling target for 
the control period determined under paragraph (d)(3)(ii) of this 
section. The allowances will be deducted on a first-in, first-out basis 
in the order set forth in Sec.  97.1024(c)(2)(i) and (ii).

[[Page 20216]]

    (iv) Record the deductions under paragraph (d)(3)(iii) of this 
section in the account.
    (4)(i) In computing any amounts of CSAPR NOX Ozone 
Season Group 3 allowances to be deducted from general accounts under 
paragraph (d)(3) of this section, the Administrator may group multiple 
general accounts whose ownership interests are held by the same or 
related persons or entities and treat the group of accounts as a single 
account for purposes of such computation.
    (ii) Following a computation for a group of general accounts in 
accordance with paragraph (d)(4)(i) of this section, the Administrator 
will deduct from and record in each individual account in such group a 
proportional share of the quantity of CSAPR NOX Ozone Season 
Group 3 allowances computed for such group, basing such shares on the 
respective quantities of CSAPR NOX Ozone Season Group 3 
allowances determined for such individual accounts under paragraph 
(d)(3)(i) of this section.
    (iii) In determining the proportional shares under paragraph 
(d)(4)(ii) of this section, the Administrator may employ any reasonable 
adjustment methodology to truncate or round each such share up or down 
to a whole number and to cause the total of such whole numbers to equal 
the amount of CSAPR NOX Ozone Season Group 3 allowances 
computed for such group of accounts in accordance with paragraph 
(d)(4)(i) of this section, even where such adjustments cause the 
numbers of CSAPR NOX Ozone Season Group 3 allowances 
remaining in some individual accounts following the deductions to equal 
zero.
0
80. Amend Sec.  97.1030 by:
0
a. Revising paragraph (b)(1); and
0
b. In paragraph (b)(3), removing ``(b)(2)'' and adding in its place 
``(b)(1) or (2)''.
    The revision reads as follows:


Sec.  97.1030   General monitoring, recordkeeping, and reporting 
requirements.

* * * * *
    (b) * * *
    (1)(i) May 1, 2021, for a unit in a State (and Indian country 
within the borders of such State) listed in Sec.  52.38(b)(2)(iii)(A) 
of this chapter;
    (ii) May 1, 2023, for a unit in a State (and Indian country within 
the borders of such State) listed in Sec.  52.38(b)(2)(iii)(B) of this 
chapter;
    (iii) [EFFECTIVE DATE OF FINAL RULE], for a unit in a State (and 
Indian country within the borders of such State) listed in Sec.  
52.38(b)(2)(iii)(C) of this chapter, where the unit is required to 
report NOX mass emissions data or NOX emissions 
rate data according to 40 CFR part 75 to address other regulatory 
requirements; or
    (iv) [180 DAYS AFTER EFFECTIVE DATE OF FINAL RULE] for a unit in a 
State (and Indian country within the borders of such State) listed in 
Sec.  52.38(b)(2)(iii)(C) of this chapter, where the unit is not 
required to report NOX mass emissions data or NOX 
emissions rate data according to 40 CFR part 75 to address other 
regulatory requirements.
* * * * *
0
81. Amend Sec.  97.1034 by:
0
a. Revising paragraph (d)(2)(i); and
0
b. In paragraph (d)(4), removing ``or CSAPR SO2 Group 1 
Trading Program, quarterly'' and adding in its place ``CSAPR 
SO2 Group 1 Trading Program, or CSAPR SO2 Group 2 
Trading Program, quarterly''.
    The revision reads as follows:


Sec.  97.1034   Recordkeeping and reporting.

* * * * *
    (d) * * *
    (2) * * *
    (i)(A) The calendar quarter covering May 1, 2021 through June 30, 
2021, for a unit in a State (and Indian country within the borders of 
such State) listed in Sec.  52.38(b)(2)(iii)(A) of this chapter;
    (B) The calendar quarter covering May 1, 2023 through June 30, 
2023, for a unit in a State (and Indian country within the borders of 
such State) listed in Sec.  52.38(b)(2)(iii)(B) of this chapter; or
    (C) The calendar quarter covering [EFFECTIVE DATE OF FINAL RULE] 
through June 30, 2023, for a unit in a State (and Indian country within 
the borders of such State) listed in Sec.  52.38(b)(2)(iii)(C) of this 
chapter;
* * * * *
[FR Doc. 2022-04551 Filed 3-30-22; 4:15 pm]
BILLING CODE 6560-50-P