[Federal Register Volume 88, Number 107 (Monday, June 5, 2023)]
[Rules and Regulations]
[Pages 36654-36918]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-05744]



[[Page 36653]]

Vol. 88

Monday,

No. 107

June 5, 2023

Part II





Environmental Protection Agency





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





Federal ``Good Neighbor Plan'' for the 2015 Ozone National Ambient Air 
Quality Standards; Final Rule

  Federal Register / Vol. 88 , No. 107 / Monday, June 5, 2023 / Rules 
and Regulations  

[[Page 36654]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 52, 75, 78, and 97

[EPA-HQ-OAR-2021-0668; FRL-8670-02-OAR]
RIN 2060-AV51


Federal ``Good Neighbor Plan'' for the 2015 Ozone National 
Ambient Air Quality Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action finalizes Federal Implementation Plan (FIP) 
requirements to address 23 states' obligations to eliminate significant 
contribution to nonattainment, or interference with maintenance, of the 
2015 ozone National Ambient Air Quality Standards (NAAQS) in other 
states. The U.S. Environmental Protection Agency (EPA) is taking this 
action under the ``good neighbor'' or ``interstate transport'' 
provision of the Clean Air Act (CAA or Act). The Agency is defining the 
amount of ozone-precursor emissions (specifically, nitrogen oxides) 
that constitute significant contribution to nonattainment and 
interference with maintenance from these 23 states. With respect to 
fossil fuel-fired power plants in 22 states, this action will prohibit 
those emissions by implementing an allowance-based trading program 
beginning in the 2023 ozone season. With respect to certain other 
industrial stationary sources in 20 states, this action will prohibit 
those emissions through emissions limitations and associated 
requirements beginning in the 2026 ozone season. These industrial 
source types are: reciprocating internal combustion engines in Pipeline 
Transportation of Natural Gas; kilns in Cement and Cement Product 
Manufacturing; reheat furnaces in Iron and Steel Mills and Ferroalloy 
Manufacturing; furnaces in Glass and Glass Product Manufacturing; 
boilers in Iron and Steel Mills and Ferroalloy Manufacturing, Metal Ore 
Mining, Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, and Pulp, Paper, and Paperboard Mills; and combustors 
and incinerators in Solid Waste Combustors and Incinerators.

DATES: This final rule is effective on August 4, 2023.

ADDRESSES: The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2021-0668. All documents in the docket are 
listed in the https://www.regulations.gov index. Although listed in the 
index, some information is not publicly available, e.g., Confidential 
Business Information or other information whose disclosure is 
restricted by statute. Certain other material, such as copyrighted 
material, will be publicly available only in hard copy. Publicly 
available docket materials are available either electronically at 
https://www.regulations.gov or in hard copy at the U.S. Environmental 
Protection Agency, EPA Docket Center, William Jefferson Clinton West 
Building, Room 3334, 1301 Constitution Ave. NW, Washington, DC. The 
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 
Friday, excluding legal holidays. The telephone number for the Public 
Reading Room is (202) 566-1744, and the telephone number for the Office 
of Air and Radiation Docket is (202) 566-1742.

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: (312) 886-4746; 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
ABC Associated Builders and Contractors
ACS American Community Survey
ACT Alternative Control Techniques
AEO Annual Energy Outlook
AQAT Air Quality Assessment Tool
AQS Air Quality System
BACT Best Available Control Technology
BART Best Available Retrofit Technology
BOF Basic Oxygen Furnace
BPT Benefit Per Ton
C1C2 Category 1 and Category 2
C3 Category 3
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
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS Continuous Emissions Monitoring Systems
CES Clean Energy Standards
CFB Circulating Fluidized Bed Units
CHP Combined Heat and Power
CMDB Control Measures Database
CMV Commercial Marine Vehicle
CoST Control Strategy Tool
CPT Cost Per Ton
CRA Congressional Review Act
CSAPR Cross-State Air Pollution Rule
DAHS Data Acquisition and Handling System
DOE Department of Energy
EAF Electric Arc Furnace
EGU Electric Generating Unit
EIA U.S. Energy Information Agency
EIS Emissions Inventory System
EISA Energy Independence and Security Act
ELG Effluent Limitation Guidelines
E.O. Executive Order
EPA or the Agency United States Environmental Protection Agency
ERT Electronic Reporting Tool
FERC Federal Energy Regulatory Commission
FFS Findings of Failure to Submit
FIP Federal Implementation Plan
GIS Geographic Information System
g/hp-hr grams per horsepower per hour
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
IRA Inflation Reduction Act
LAER Lowest Achievable Emission Rate
LDC Local Distribution Company
LME Low Mass Emissions
LNB Low-NOX Burners
MATS Mercury and Air Toxics Standards
MCM Menu of Control Measures
MDA8 Maximum Daily Average 8-Hour
MJO Multi-Jurisdictional Organization
MOU Memorandum of Understanding
MOVES Motor Vehicle Emissions Simulator
MSAT2 Mobile Source Air Toxics Rule
MWC Municipal Waste Combustor
NAAQS National Ambient Air Quality Standards
NACAA National Association of Clean Air Agencies
NAICS North American Industry Classification System
NEEDS National Electric Energy Data System
NEI National Emissions Inventory
NERC North American Electric Reliability Corporation
NESHAP National Emissions Standards for Hazardous Air Pollutants
NMB Normalized Mean Bias
NME Normalized Mean Error
No SISNOSE No Significant Economic Impact on a Substantial Number of 
Small Entities
Non-EGU Non-Electric Generating Unit
NODA Notice of Data Availability
NOX Nitrogen Oxides
NREL National Renewable Energy Lab
NSCR Non-Selective Catalytic Reduction
NSPS New Source Performance Standard
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
OFA Over-Fire Air
OMB United States Office of Management and Budget

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OSAT/APCA Ozone Source Apportionment Technology/Anthropogenic 
Precursor Culpability Analysis
OTC Ozone Transport Commission
OTR Ozone Transport Region
OTSA Oklahoma Tribal Statistical Area
PDF Portable Document Format
PEMS Predictive Emissions Monitoring Systems
PM2.5 Fine Particulate Matter
ppb parts per billion
ppm parts per million
ppmv parts per million by volume
ppmvd parts per million by volume, dry
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
PTE Potential to Emit
RACT Reasonably Available Control Technology
RATA Relative Accuracy Test Audit
RCF Relative Contribution Factor
RFA Regulatory Flexibility Act
RICE Reciprocating Internal Combustion Engines
ROP Rate of Progress
RPS Renewable Portfolio Standards
RRF Relative Response Factor
RTC Response to Comments
RTO Regional Transmission Organization
SAFETEA Safe, Accountable, Flexible, Efficient, Transportation 
Equity Act
SCC Source Classification Code
SCR Selective Catalytic Reduction
SIL Significant Impact Level
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel Emissions
SNCR Selective Non-Catalytic Reduction
SO2 Sulfur Dioxide
tpd ton per day
TAS Treatment as State
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 the Regulatory Action
    1. Emissions Limitations for EGUs Established by the Final Rule
    2. Emissions Limitations for Industrial Stationary Point Sources 
Established by the Final Rule
    B. Summary of the Regulatory Framework of the Rule
    C. Costs and Benefits
II. 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?
    D. What actions has the EPA previously issued to address 
regional ozone transport?
III. Air Quality Issues Addressed and Overall Rule Approach
    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. Final 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 Rule
    C. Other CAA Authorities for This Action
    1. Withdrawal of Proposed Error Correction for Delaware
    2. Application of Rule in Indian Country and Necessary or 
Appropriate Finding
    a. Indian Country Subject to Tribal Jurisdiction
    b. Indian Country Subject to State Implementation Planning 
Authority
    D. Severability
IV. 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
    a. EGU Emissions Inventories Supporting This Rule
    b. Impact of the Inflation Reduction Act on EGU Emissions
    3. Development of Emissions Inventories for Stationary 
Industrial 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. Methodology for Projecting Future Year Ozone Design Values
    F. Pollutant Transport From Upwind States
    1. Air Quality Modeling To Quantify Upwind State Ozone 
Contributions
    2. Application of Ozone Contribution Screening Threshold
    a. States That Contribute Below the Screening Threshold
    b. States That Contribute Above the Screening Threshold
    G. Treatment of Certain Monitoring Sites in California and 
Implications for Oregon's Good Neighbor Obligations for the 2015 
Ozone NAAQS
V. 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
    g. Other EGU Mitigation Measures
    2. Non-EGU or Stationary Industrial Source NOX 
Mitigation Strategies
    3. Other Stationary Sources NOX Mitigation Strategies
    a. Municipal Solid Waste Units
    b. Electric Generating Units Less Than or Equal to 25 MW
    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 or Industrial Source Emissions Reduction Potential
    D. Assessing Cost, EGU and Industrial Source NOX 
Reductions, and Air Quality
    1. EGU Assessment
    2. Stationary Industrial Sources Assessment
    3. Combined EGU and Non-EGU Assessment
    4. Over-Control Analysis
VI. 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 Stationary Industrial Source 
NOX Reductions Beginning in 2026
    a. EGU Schedule for 2026 and Later Years
    b. Non-EGU or Industrial Source Schedule for 2026 and Later 
Years
    B. Regulatory Requirements for EGUs
    1. Trading Program Background and Overview of 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
    d. Responses to General Comments on the Revisions to the Group 3 
Trading Program
    2. Expansion of Geographic Scope
    3. Applicability and Tentative Identification of Newly Affected 
Units
    4. State Emissions Budgets
    a. Methodology for Determining Preset State Emissions Budgets 
for the 2023 through 2029 Control Periods
    b. Methodology for Determining Dynamic State Emissions Budgets 
for Control Periods in 2026 Onwards
    c. Final Preset 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

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    9. Unit-Level Allowance Allocation and Recordation Procedures
    a. Set-Asides of Portions of State Emissions Budgets
    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. Monitoring and Reporting Requirements
    a. Monitor Certification Deadlines
    b. Additional Recordkeeping and Reporting Requirements
    11. Designated Representative Requirements
    12. Transitional Provisions
    a. Prorating Emissions Budgets, Assurance Levels, and Unit-Level 
Allowance 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
    13. Conforming Revisions to Regulations for Other CSAPR Trading 
Programs
    C. Regulatory Requirements for Stationary Industrial Sources
    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 at Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, Pulp, Paper, and Paperboard Mills, Iron and 
Steel and Ferroalloys Manufacturing, and Metal Ore Mining Facilities
    a. Coal-fired Industrial Boilers
    b. Oil-fired Industrial Boilers
    c. Natural gas-fired Industrial Boilers
    6. Municipal Waste Combustors
    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 or Industrial Source 
Control Requirements
    E. Title V Permitting
    1. Title V Permitting Considerations for EGUs
    2. Title V Permitting Considerations for Industrial Stationary 
Sources
    F. Relationship to Other Emissions Trading and Ozone Transport 
Programs
    1. NOX SIP Call
    2. Acid Rain Program
    3. Other CSAPR Trading Programs
VII. Environmental Justice Analytical Considerations and Stakeholder 
Outreach and Engagement
    A. Introduction
    B. Analytical Considerations
    C. Outreach and Engagement
VIII. Costs, Benefits, and Other Impacts of the Final Rule
IX. Summary of 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
X. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    1. Information Collection Request for EGUs
    2. Information Collection Request for Non-EGUs
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act
    L. Determinations Under CAA Section 307(b)(1) and (d)

I. Executive Summary

    This final rule resolves the interstate transport obligations of 23 
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 submit to EPA ozone 
infrastructure State Implementation Plan (SIP) revisions to fulfill 
interstate transport obligations for the 2015 ozone NAAQS by October 1, 
2018. The EPA proposed the subject rule to address outstanding 
interstate ozone transport obligations for the 2015 ozone NAAQS in the 
Federal Register on April 6, 2022 (87 FR 20036).
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    \1\ See 80 FR 65291 (October 26, 2015).
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    The EPA is making a finding that interstate transport of ozone 
precursor emissions from 23 upwind states (Alabama, Arkansas, 
California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and 
Wisconsin) is significantly contributing to nonattainment or 
interfering with maintenance of the 2015 ozone NAAQS in downwind 
states, based on projected ozone precursor emissions in the 2023 ozone 
season. The EPA is issuing FIP requirements to eliminate interstate 
transport of ozone precursor emissions from these 23 states that 
significantly contributes to nonattainment or interferes with 
maintenance of the NAAQS in downwind states. The EPA is not finalizing 
its proposed error correction for Delaware's ozone transport SIP, and 
we are deferring final action at this time on the proposed FIPs for 
Tennessee and Wyoming pending further review of the updated air quality 
and contribution modeling and analysis developed for this final action. 
As discussed in section III of this document, the EPA's updated 
analysis of 2023 suggests that the states of Arizona, Iowa, Kansas, and 
New Mexico may be significantly contributing to one or more 
nonattainment or maintenance receptors. The EPA is not making any final 
determinations with respect to these states in this action but intends 
to address these states, along with Tennessee and Wyoming, in a 
subsequent action or actions.
    The EPA is finalizing FIP requirements for 21 states for which the 
Agency has, in a separate action, disapproved (or partially 
disapproved) ozone transport SIP revisions that were 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, Texas, Utah, 
West Virginia, and Wisconsin. See 88 FR 9336. In this final rule, the 
EPA is issuing FIPs for two states--Pennsylvania and Virginia--for 
which the EPA issued Findings of Failure to Submit for 2015 ozone NAAQS 
transport SIPs. See 84 FR 66612 (December 5, 2019). Under CAA section 
301(d)(4), the EPA is extending FIP requirements to apply in Indian 
country located within the upwind geography of the final 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\
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    \2\ In general, specific tribal names or reservations are not 
identified separately in this final rule except as needed. See 
section III.C.2 of this document for further discussion about the 
application of this rule in Indian Country.
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    This final rule defines ozone season nitrogen oxides 
(NOX) emissions

[[Page 36657]]

performance obligations for Electric Generating Unit (EGU) sources and 
fulfills those obligations by implementing an allowance-based ozone 
season trading program beginning in 2023. This rule also establishes 
emissions limitations beginning in 2026 for certain other industrial 
stationary sources (referred to generally as ``non-Electric Generating 
Units'' (non-EGUs)). Taken together, these regulatory requirements will 
fully eliminate the amount of emissions that constitute the covered 
states' significant contribution to nonattainment and interference with 
maintenance in downwind states for purposes of the 2015 ozone NAAQS.
    This final rule implements the necessary emissions reductions as 
follows. Under the FIP requirements, EGUs in 22 states (Alabama, 
Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and 
Wisconsin) are required 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\ In addition to reflecting emissions reductions based 
on the Agency's determination of the necessary control stringency in 
this rule, the revised trading program includes several enhancements to 
the program's design to better ensure achievement of the selected 
control stringency on all days of the ozone season and over time. For 
12 states already required to participate 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) under the Revised CSAPR 
Update (with respect to the 2008 ozone NAAQS), the FIPs are amended by 
the revisions to the Group 3 trading program regulations. For seven 
states currently covered by the CSAPR NOX Ozone Season Group 
2 Trading Program under SIPs or FIPs, the EPA is issuing new FIPs for 
two states (Alabama and Missouri) and amending existing FIPs for five 
states (Arkansas, Mississippi, Oklahoma, 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. 
The EPA is issuing new FIPs for three states not currently covered by 
any CSAPR NOX ozone season trading program: Minnesota, 
Nevada, and Utah.
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    \3\ As explained in section V.C.1 of this document, the EPA is 
making a 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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    This rulemaking requires emissions reductions in the selected 
control stringency to be achieved as expeditiously as practicable and, 
to the extent possible, by the next applicable nonattainment dates for 
downwind areas for the 2015 ozone NAAQS. Thus, initial emissions 
reductions from EGUs will be required beginning in the 2023 ozone 
season and prior to the August 3, 2024, attainment date for areas 
classified as Moderate nonattainment for the 2015 ozone NAAQS.
    The remaining emissions reduction obligations will be phased in as 
soon as possible thereafter. Substantial additional reductions from 
potential new post-combustion control installations at EGUs as well as 
from installation of new pollution controls at non-EGUs, also referred 
to in this action as industrial sources, will phase in beginning in the 
2026 ozone season, associated with the August 3, 2027, attainment date 
for areas classified as Serious nonattainment for the 2015 ozone NAAQS. 
The EPA had proposed to require all emissions reductions to eliminate 
significant contribution to be in place by the 2026 ozone season. While 
we continue to view 2026 as the appropriate analytic year for purposes 
of applying the 4-step interstate transport framework, as discussed in 
section V.D.4 and VI.A.2 of this document, the final rule will allow 
individual facilities limited additional time to fully implement the 
required emissions reductions where the owner or operator demonstrates 
to the EPA's satisfaction that more rapid compliance is not possible. 
For EGUs, the emissions trading program budget stringency associated 
with retrofit of post-combustion controls will be phased in over two 
ozone seasons (2026-2027). For industrial sources, this final rule 
provides a process for individual facilities to seek a one year 
extension, with the possibility of up to two additional years, based on 
a specific showing of necessity.
    The EGU emissions reductions are based on the feasibility of 
control installation for EGUs in 19 states that remain linked to 
downwind nonattainment and maintenance receptors in 2026. These 19 
states are: Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, and West Virginia. The 
emissions reductions required for EGUs in these states are based 
primarily on the potential retrofit of additional post-combustion 
controls for NOX on most coal-fired EGUs and a portion of 
oil/gas-fired EGUs that are currently lacking such controls.
    The EPA is finalizing, with some modifications from proposal in 
response to comments, certain additional features in the allowance-
based trading program approach for EGUs, including dynamic adjustments 
of the emissions budgets and recalibration of the allowance bank over 
time as well as backstop daily emissions rate limits for large coal-
fired units. The purpose of these enhancements is to better ensure that 
the emissions control stringency the EPA found necessary to eliminate 
significant contribution at Step 3 of the 4-step interstate transport 
framework is maintained over time in Step 4 implementation and is 
durable to changes in the power sector. These enhancements ensure the 
elimination of significant contribution is maintained both in terms of 
geographical distribution (by limiting the degree to which individual 
sources can avoid making emissions reductions) and in terms of temporal 
distribution (by better ensuring emissions reductions are maintained 
throughout each ozone season, year over year). As we further discuss in 
section V.D of this document, these changes do not alter the stringency 
of the emissions trading program over time. Rather, they ensure that 
the trading program (as the method of implementation at Step 4) remains 
aligned with the determinations made at Step 3. These enhancements are 
further discussed in section VI.B of this document.
    The EPA is making a finding that NOX emissions from 
certain 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 is 
establishing emissions limitations beginning in 2026 for non-EGU 
sources located within 20 states: Arkansas, California, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, 
Texas, Utah, Virginia, and West Virginia. The final rule establishes 
NOX emissions limitations during the ozone season for the 
following unit types for sources in

[[Page 36658]]

non-EGU industries: \4\ reciprocating internal combustion engines in 
Pipeline Transportation of Natural Gas; kilns in Cement and Cement 
Product Manufacturing; reheat furnaces in Iron and Steel Mills and 
Ferroalloy Manufacturing; furnaces in Glass and Glass Product 
Manufacturing; boilers in Iron and Steel Mills and Ferroalloy 
Manufacturing, Metal Ore Mining, Basic Chemical Manufacturing, 
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and 
Paperboard Mills; and combustors and incinerators in Solid Waste 
Combustors and Incinerators.
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    \4\ We use the terms ``emissions limitation'' and ``emissions 
limit'' to refer to both numeric emissions limitations and control 
technology requirements that specify levels of emissions reductions 
to be achieved.
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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 downwind 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 certain 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 III of this document 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.5 6 
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.\7\
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    \5\ 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.
    \6\ 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.
    \7\ 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.\8\ Within 3 years of the EPA promulgating a 
new or revised NAAQS, all states are required to provide SIP 
submittals, often referred to as ``infrastructure SIPs,'' addressing 
certain requirements, including the good neighbor provision. See CAA 
section 110(a)(1) and (2). The EPA must either approve or disapprove 
such submittals or make a finding that a state has failed to submit a 
complete SIP revision. As with any other type of SIP under the Act, 
when the EPA disapproves an interstate transport SIP or finds that a 
state failed to submit an interstate transport SIP, the CAA requires 
the EPA to issue a FIP to directly implement the measures necessary to 
eliminate significant contribution under the good neighbor provision. 
See generally CAA section 110(k) and 110(c). As such, in this rule, the 
EPA is finalizing requirements to fully address good neighbor 
obligations for the covered states for the 2015 ozone NAAQS under its 
authority to promulgate FIPs under CAA section 110(c). By eliminating 
significant contribution from these upwind states, this rule 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. At any time after the effective date of this 
rule, states may submit a Good Neighbor SIP to replace the FIP 
requirements contained in this rule, subject to EPA approval under CAA 
section 110(a).
---------------------------------------------------------------------------

    \8\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
---------------------------------------------------------------------------

    The EPA conducted air quality modeling for the 2023 and 2026 
analytic years to identify (1) the downwind areas identified as 
``receptors'' (which are associated with monitoring sites) 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. We use the term 
``downwind'' to describe those states or areas where a receptor is 
located, and we use the term ``upwind'' to describe states whose 
emissions are linked to one or more receptors. States may be both 
downwind and upwind depending on the receptor or linkage in question. 
Section IV of this document provides a full description of the results 
of the EPA's updated air quality modeling and relevant analyses for the 
rulemaking, including a discussion of how updates to the modeling and 
air quality analysis following the proposed rule have resulted in some 
modest changes in the overall geography of the final rule. Based on the 
EPA's air quality analysis, the 23 upwind states covered in this action 
are linked above the 1 percent of the NAAQS threshold to downwind air 
quality problems in downwind states. The EPA intends to expeditiously 
review the updated air quality modeling and related analyses to address 
potential good neighbor requirements of six additional states--Arizona, 
Iowa, Kansas, New Mexico, Tennessee, and Wyoming--in a subsequent 
action. The EPA had previously approved 2015 ozone transport SIPs 
submitted by Oregon and Delaware, but in the proposed FIP action the 
EPA found these states potentially to be linked in the modeling 
supporting our proposal. We proposed to issue an error correction for 
our prior approval of Delaware's 2015 ozone transport SIP; however, in 
this final rule, the EPA is withdrawing the proposed error correction 
and the proposed FIP for Delaware, because our updated modeling for 
this final rule confirms that Delaware is not linked above the 1 
percent of NAAQS threshold (see section III.C.1 of this document for 
additional information). The EPA is deferring finalizing a finding at 
this time for Oregon (see section IV.G of this document for additional 
information).
1. Emissions Limitations for EGUs Established by the Final Rule
    In this rule, the EPA is issuing FIP requirements that apply the 
provisions of the CSAPR NOX Ozone Season Group 3 Trading 
Program as revised in the rule to EGU sources within the borders of the 
following 22 states: Alabama, Arkansas, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, 
Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, 
Utah, Virginia, West Virginia, and Wisconsin. Implementation of the 
revised trading program provisions begins in the 2023 ozone season.
    The EPA is expanding the CSAPR NOX Ozone Season Group 3 
Trading Program beginning in the 2023 ozone season. Specifically, the 
FIPs require power plants within the borders of the 22 states listed in 
the previous paragraph to participate in an expanded and revised 
version of the CSAPR NOX Ozone Season Group 3 Trading 
Program created by the Revised CSAPR Update. Affected EGUs within the 
borders of the following 12 states currently participating in the Group 
3 Trading Program under existing FIPs remain in the program, with 
revised provisions beginning in the 2023 ozone season, under this rule: 
Illinois, Indiana, Kentucky, Louisiana, Maryland,

[[Page 36659]]

Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West 
Virginia. The FIPs also require affected EGUs within the borders of the 
following seven 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, 
Texas, and Wisconsin.\9\ Finally, the EPA is issuing new FIPs for EGUs 
within the borders of three states not currently covered by any 
existing CSAPR trading program for seasonal NOX emissions: 
Minnesota, Nevada, and Utah. Sources in these states will enter the 
Group 3 trading program in the 2023 control period following the 
effective date of the final rule.\10\ Refer to section VI.B of this 
document for details on EGU regulatory requirements.
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    \9\ Five of these seven states (Arkansas, Mississippi, Oklahoma, 
Texas, and Wisconsin) currently participate in the Federal Group 2 
trading program pursuant to the FIPs finalized in the CSAPR Update. 
The FIPs required under this rule 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 required in this action constitute new FIPs for 
these states. The EPA will cease implementation of the state Group 2 
trading programs included in the two states' SIPs on the effective 
date of this rule.
    \10\ Three states, Kansas, Iowa, and Tennessee, will remain in 
the Group 2 Trading Program.
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2. Emissions Limitations for Industrial Stationary Point Sources 
Established by the Final Rule
    The EPA is issuing FIP requirements that include new NOX 
emissions limitations for industrial or non-EGU sources in 20 states, 
with sources expected to demonstrate compliance no later than 2026. The 
EPA is requiring emissions reductions from non-EGU sources to address 
interstate transport obligations for the 2015 ozone NAAQS for the 
following 20 states: Arkansas, California, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New 
Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia 
and West Virginia.
    The EPA is establishing emissions limitations for the following 
unit types in non-EGU industries: reciprocating internal combustion 
engines in Pipeline Transportation of Natural Gas; kilns in Cement and 
Cement Product Manufacturing; reheat furnaces in Iron and Steel Mills 
and Ferroalloy Manufacturing; furnaces in Glass and Glass Product 
Manufacturing; boilers in Iron and Steel Mills and Ferroalloy 
Manufacturing, Metal Ore Mining, Basic Chemical Manufacturing, 
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and 
Paperboard Mills; and combustors and incinerators in Solid Waste 
Combustors and Incinerators. Refer to Table II.A-1 for a list of North 
American Industry Classification System (NAICS) codes for each entity 
included for regulation under this rule.

B. Summary of the Regulatory Framework of the Rule

    The EPA is applying the 4-step interstate transport framework 
developed and used in CSAPR, the CSAPR Update, the Revised CSAPR 
Update, and other previous ozone transport rules 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 define 
and implement good neighbor obligations for the 2015 ozone NAAQS. The 
four steps are as follows: (Step 1) identifying downwind receptors that 
are expected to have problems attaining or maintaining the NAAQS; (Step 
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 rule as in prior transport rules 
beginning with CSAPR in 2011, above a contribution threshold of 1 
percent of the NAAQS); (Step 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 through a multifactor analysis; and (Step 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. The remainder of this section provides a 
general overview of the EPA's application of the 4-step framework as it 
applies to the provisions of the rule; additional details regarding the 
EPA's approach are found in section III of this document.
    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 and 2026.\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 of projected ozone concentrations was then 
repeated for 2026.
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    \11\ These 2 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, and August 3, 2027, for areas classified as Serious 
nonattainment. See 83 FR 25776.
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    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, the 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 
4-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.
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    \12\ The EPA performed air quality modeling for 2032 in the 
proposed rulemaking, but 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. The modeling of 
2032 done at proposal using the 2016v2 platform does not constitute 
or represent any final agency determinations respecting air quality 
conditions or regulatory judgments with respect to good neighbor 
obligations or any other CAA requirements.
    \13\ See section IV.F of this document for explanation of EPA's 
use of the 1 percent of the NAAQS threshold in the Step 2 analysis.
---------------------------------------------------------------------------

    Based on the EPA's most recent air quality modeling and 
contribution analysis using 2023 as the analytic year, the EPA finds 
that the following 23 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, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, West Virginia, and Wisconsin.
    There are locations in California to which Oregon contributes 
greater than 1 percent of the NAAQS; the EPA

[[Page 36660]]

proposed that downwind areas represented by these monitoring sites in 
California should not be considered interstate ozone transport 
receptors at Step 1. However, the EPA is deferring finalizing a finding 
at this time for Oregon (see section IV.G of this document for 
additional information).
    Based on the air quality analysis presented in section IV of this 
document, the EPA finds that, with the exception of Alabama, Minnesota, 
and Wisconsin, the states found linked in 2023 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. As a result, the EPA's evaluation of 
significantly contributing emissions at Step 3 for Alabama, Minnesota, 
and Wisconsin is limited to emissions reductions achievable by the 2023 
and 2024 ozone seasons.
    At the third step of the 4-step framework, the EPA applied a 
multifactor 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. The EPA is applying the 
multifactor test described in section V.A of this document to both EGU 
and industrial sources. The EPA assessed the potential emissions 
reductions in 2023 and 2026,\14\ as well as in intervening and later 
years to determine the emissions reductions required to eliminate 
significant contribution in 2023 and future years where downwind areas 
are projected to have potential problems attaining or maintaining the 
2015 ozone NAAQS.
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    \14\ The EPA included emissions reductions from the potential 
installation of SCRs at all affected large coal-fired EGUs in the 
2026 analytic year for the purposes of assessing significant 
contribution to nonattainment and interference with maintenance, 
which is consistent with the associated attainment date. However, in 
response to comments identifying potential supply chain and outage 
scheduling challenges if the full breadth of these assumed SCR 
installations were to occur, the EPA is implementing half of this 
emissions reduction potential in 2026 ozone-season NOX 
budgets for states containing these EGUs and the other half of this 
emissions reduction potential in 2027 ozone-season NOX 
budgets for those states.
---------------------------------------------------------------------------

    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 V of this document and 
supported by the ``Technical Support Document (TSD) for the Final 
Federal Good Neighbor Plan for the 2015 Ozone National Ambient Air 
Quality Standard, Docket ID No. EPA-HQ-OAR-2021-0668, EGU 
NOX Mitigation Strategies Final Rule TSD'' (Mar. 2023), 
hereinafter referred to as the EGU NOX Mitigation Strategies 
Final Rule TSD, included in the docket for this action, the EPA 
determines 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. See section V.B.1 of this document 
for a full discussion of EPA's analysis of NOX emissions 
mitigation strategies for EGU sources.
    The EPA is requiring control stringency levels that offer the most 
incremental NOX emissions reduction potential from EGUs--
among the uniform mitigation measures assessed for the covered region--
and the most corresponding downwind ozone air quality improvements to 
the extent feasible in each year analyzed. The EPA is making a finding 
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 the 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.\15\ 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.
---------------------------------------------------------------------------

    \15\ 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 rulemaking, the EPA is addressing good neighbor obligations 
for the more protective 2015 ozone NAAQS, and the Agency observes 
ongoing and persistent contribution from upwind states to ozone 
nonattainment and maintenance receptors in downwind states under that 
NAAQS. As further discussed in section V of this document, 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. In this 
rule, the EPA is requiring emissions performance levels for 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 V of this 
document, the EPA finds 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 22 
states linked to downwind

[[Page 36661]]

nonattainment or maintenance in 2023 (Alabama, Arkansas, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, West Virginia, and Wisconsin). For 
19 of those states that are also linked in 2026 (Arkansas, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, 
Texas, Utah, Virginia, and West Virginia), the EPA is determining that 
the selected EGU control stringency also includes emissions reductions 
commensurate with the retrofit of SCR at coal-fired units of 100 MW or 
greater capacity (excepting circulating fluidized bed units (CFB)), new 
SNCR on coal-fired units of less than 100 MW capacity and on CFBs of 
any capacity size, 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, for the proposed 
FIP, the EPA evaluated air quality modeling information, annual 
emissions, and information about potential controls to determine which 
industries, beyond the power sector, could have the greatest impact in 
providing ozone air quality improvements in affected downwind states. 
Once the EPA identified the industries, the EPA used its Control 
Strategy Tool to identify potential emissions units and control 
measures and to estimate emissions reductions and compliance costs 
associated with application of non-EGU emissions control measures. The 
technical memorandum Screening Assessment of Potential Emissions 
Reductions, Air Quality Impacts, and Costs from Non-EGU Emissions Units 
for 2026 lays out the analytical framework and data used to prepare 
proxy estimates for 2026 of potentially affected non-EGU facilities and 
emissions units, emissions reductions, and costs.16 17 This 
information helped shape the proposal and final rule. To further 
evaluate the industries and emissions unit types identified by the 
screening assessment and to establish the applicability criteria and 
proposed emissions limits, the EPA reviewed Reasonably Available 
Control Technology (RACT) rules, New Source Performance Standards 
(NSPS) rules, National Emissions Standards for Hazardous Air Pollutants 
(NESHAP) rules, existing technical studies, rules in approved SIPs, 
consent decrees, and permit limits. That evaluation is detailed in the 
``Technical Support Document (TSD) for the Proposed Rule, Docket ID No. 
EPA-HQ-OAR-2021-0668, Non-EGU Sectors TSD'' (Dec. 2021), hereinafter 
referred to as the Proposed Non-EGU Sectors TSD, prepared for the 
proposed FIP.\18\
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    \16\ The memorandum is available in the docket at https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0150.
    \17\ This screening assessment was not intended to identify the 
specific emissions units subject to the proposed emissions limits 
for non-EGU sources but was intended to inform the development of 
the proposed rule by identifying proxies for (1) non-EGU emissions 
units that had 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. 
This information helped shape the proposed rule.
    \18\ The TSD is available in the docket at https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0145.
---------------------------------------------------------------------------

    In this final rule, the EPA is retaining the industries and many of 
the emissions unit types included in the proposal in its findings of 
significant contribution at Step 3, as discussed in section V of this 
document. As discussed in the memorandum for the final rule, titled 
``Summary of Final Rule Applicability Criteria and Emissions Limits for 
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the 
Final Emissions Limits, and Estimated Emissions Units, Emissions 
Reductions, and Costs,'' the EPA uses the 2019 emissions inventory, the 
list of emissions units estimated to be captured by the applicability 
criteria, the assumed control technologies that would meet the 
emissions limits, and information on control efficiencies and default 
cost/ton values from the Control Measures Database,\19\ to estimate 
NOX emissions reductions and costs for the year 2026. In 
this final rule, the EPA made changes to the applicability criteria and 
emissions limits following consideration of comments on the proposal 
and reassessed the overall non-EGU emissions reduction strategy based 
on the factors at Step 3 to render a judgment as to whether the level 
of emissions control that would be achievable from these units meets 
the criteria for ``significant contribution.'' In the final rule, we 
affirm our proposed determinations of which industries and emissions 
units are potentially impactful and warrant further analysis at Step 3, 
and we find that the available emissions reductions are cost-effective 
and make meaningful improvements at the identified downwind receptors. 
For a detailed discussion of the changes, between the proposal and this 
final rule, in emissions unit types included and in emissions limits, 
see section VI.C. of this document.
---------------------------------------------------------------------------

    \19\ More information about the control measures database (CMDB) 
can be found at the following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
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    The EPA performed air quality analysis using the Ozone Air Quality 
Assessment Tool (AQAT) to evaluate the air quality improvements 
anticipated to result from the implementation of the selected EGU and 
non-EGU emissions reduction strategies. See section V.D of this 
document.\20\ We also used AQAT to determine whether the emissions 
reductions for both EGUs and non-EGUs potentially create an ``over-
control'' scenario. As in prior transport rules following the holdings 
in EME Homer City, overcontrol would be established if the record 
indicated that, for any given state, there is a less stringent 
emissions control approach for that state, by which (1) the expected 
ozone improvements would be sufficient to resolve all of the downwind 
receptor(s) to which that 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) to 
all of linked receptors. The EPA's over-control analysis, discussed in 
section V.D.4 of this document, shows that the control stringencies for 
EGU and non-EGU sources in this final rule 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.
---------------------------------------------------------------------------

    \20\ The use of AQAT and other simplified modeling tools to 
generate ``appropriately reliable projections of air quality 
conditions and contributions'' when there is limited time to conduct 
full-scale photochemical grid modeling was upheld by the D.C. 
Circuit in MOG v. EPA, No. 21-1146 (D.C. Cir. March 3, 2023). The 
EPA has used AQAT for the purpose of air quality and overcontrol 
assessments at Step 3 in the prior CSAPR rulemakings, and we 
continue to find it reliable for such purposes. We discuss the 
calibration of AQAT for this action and the multiple sensitivity 
checks we performed to ensure its reliability in the Ozone Transport 
Policy Analysis Final Rule TSD in the docket. Because we were able 
to conduct a photochemical grid modeling run of the 2026 final rule 
policy scenario, these results are also included in the docket and 
confirm the regulatory conclusions reached with AQAT. See section 
VIII of this document and Appendix 3A of the Final Rule RIA for more 
information.
---------------------------------------------------------------------------

    Based on the multi-factor test applied to both EGU and non-EGU 
sources and

[[Page 36662]]

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 23 upwind 
states subject to EGU and non-EGU emissions reductions requirements 
under the rule. For additional details about the multi-factor test and 
the over-control analysis, see the document titled ``Technical Support 
Document (TSD) for the Final Federal Good Neighbor Plan for the 2015 
Ozone National Ambient Air Quality Standard, Docket ID No. EPA-HQ-OAR-
2021-0668, Ozone Transport Policy Analysis Proposed Rule TSD'' (Mar. 
2023), hereinafter referred to as Ozone Transport Policy Analysis Final 
Rule TSD, included in the docket for this rulemaking.
    In this fourth step of the 4-step framework, the EPA is including 
enforceable measures in the promulgated FIPs to achieve the required 
emissions reductions in each of the 23 states. Specifically, the FIPs 
require covered power plants within the borders of 22 states (Alabama, 
Arkansas, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and 
Wisconsin) to participate in the CSAPR NOX Ozone Season 
Group 3 Trading Program created by the Revised CSAPR Update. Affected 
EGUs within the borders of the following 12 states currently 
participating in the Group 3 Trading Program will remain in the 
program, with revised provisions beginning in the 2023 ozone season, 
under this rule: Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West 
Virginia. Affected EGUs within the borders of the following seven 
states currently covered by the CSAPR NOX Ozone Season Group 
2 Trading Program (the ``Group 2 trading program'')--Alabama, Arkansas, 
Mississippi, Missouri, Oklahoma, Texas, and Wisconsin--will transition 
from the Group 2 program to the revised Group 3 trading program 
beginning with the 2023 control period,\21\ and affected EGUs within 
the borders of three states not currently covered by any CSAPR trading 
program for seasonal NOX emissions--Minnesota, Nevada, and 
Utah--will enter the Group 3 trading program in the 2023 control period 
following the effective date of the final rule. In addition, the EPA is 
revising other aspects of the Group 3 trading program to better ensure 
that this method of implementation at Step 4 provides a durable remedy 
for the elimination of the amount of emissions deemed to constitute 
significant contribution at Step 3 of the interstate transport 
framework. These enhancements, summarized later in this section, are 
designed to operate together to maintain that degree of control 
stringency over time, thus improving emissions performance at 
individual units and offering a necessary measure of assurance that 
NOX pollution controls will be operated throughout each 
ozone season, as described in section VI.B of this document. This 
rulemaking does not revise the budget stringency and geography of the 
existing CSAPR NOX Ozone Season Group 1 trading program. 
Aside from the seven states moving from the Group 2 trading program to 
the Group 3 trading program under the final rule, this rule otherwise 
leaves unchanged the budget stringency of the existing CSAPR 
NOX Ozone Season Group 2 trading program.
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    \21\ The EPA will deem participation in the Group 3 trading 
program by the EGUs in these seven states as also addressing the 
respective states' good neighbor obligations with respect to the 
2008 ozone NAAQS (for all seven states), the 1997 ozone NAAQS (for 
all the states except Texas), and the 1979 ozone NAAQS (for Alabama 
and Missouri) to the same extent that those obligations are 
currently being addressed by participation of the states' EGUs in 
the Group 2 trading program.
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    The EPA is establishing preset ozone season NOX 
emissions budgets for each ozone season from 2023 through 2029, using 
generally the same Group 3 trading program budget-setting methodology 
used in the Revised CSAPR Update, as explained in section VI.B of this 
document and as shown in Table I.B-1. The preset budgets for the 2026 
through 2029 ozone seasons incorporate EGU emissions reductions to 
eliminate significant contribution and also take into account a 
substantial number of known retirements over that period to ensure the 
elimination of significant contribution is maintained as intended by 
this rule. These budgets serve as floors and may be supplanted by a 
budget that the EPA calculates for that control period using more 
recent information (a ``dynamic budget'') if that dynamic budget yields 
a higher level of allowable emissions--still consistent with the Step 3 
level of emissions control stringency--than the preset budget. As 
reflected in Table I.B-1, and accounting for both the stringency of the 
rule and known fleet change, the 2026 preset budget is 23 percent lower 
than the 2025 preset budget; the 2027 preset budget is 20 percent lower 
than the 2026 preset budget; the 2028 preset budget is 4 percent lower 
than the 2027 preset budget; and the 2029 preset budget is 8 percent 
lower than the 2028 preset budget.
    While it is possible that additional EGUs may seek to retire in 
this 2026-2029 period than are currently scheduled and captured in the 
preset emissions budgets, it is also possible that EGUs with currently 
scheduled retirements may adjust their retirement timing to accommodate 
the timing of replacement generation and/or transmission upgrades 
necessitated by their retirement. While the EPA designed this final 
rule to provide preset budgets through 2029 to incorporate known 
retirement-related emissions reductions to ensure the elimination of 
significant contribution as identified at Step 3 is maintained over 
time, the use of these floors also provides generators and grid 
operators enhanced certainty regarding the minimum amount of allowable 
NOX emissions for reliability planning through the 2020s. By 
providing the opportunity for dynamic budgets to subsequently calibrate 
budgets to any unforeseen increases in fleet demand, it also ensures 
this rule will not interfere with ongoing retirement scheduling or 
adjustments and thus is robust to future uncertainty during a 
transition period.
    The EPA also believes the likelihood and magnitude of a scenario in 
which a state's preset emissions budgets during this period would 
authorize more emissions than the corresponding dynamic budget is low. 
As described elsewhere, dynamic budgets are incorporated to best 
calibrate the rule's stringency to future unknown changes to the fleet. 
The circumstances in which a dynamic budget would produce a level of 
allowable emissions less than preset budgets is most pronounced for 
future periods in which there is a high degree of unknown retirements 
(increasing the risk that budgets are not appropriately calibrated to 
the reduced fossil fuel heat input post retirement). However, the 2026-
2029 period presents a case where retirement planning has been 
announced with greater lead time than normal due to a combination of 
utility 2030 decarbonization commitments, and Effluent Limitation 
Guideline (ELG) and Coal Combustion Residual (CCR) alternative 
compliance pathways available to units planning to cease combustion of 
coal by December 31, 2028. For each of these existing rules, facilities 
that are planning to retire have already conveyed that intention to EPA 
in order to take advantage of the alternative compliance pathways

[[Page 36663]]

available to such facilities.\22\ Therefore, the likelihood of unknown 
retirements--leading to lower dynamic budgets--is much lower than 
typical for this time horizon. This makes EPA's balanced use of preset 
emissions budgets or dynamic budgets if they exceed preset levels a 
reasonable mechanism to accommodate planning and fleet transition 
dynamics during this period. The need and reasoning for the limited-
period preset budget floor is further discussed in section VI.B.4.
---------------------------------------------------------------------------

    \22\ Notices of Planned Participation for the ELG 
Reconsideration Rule were due October 31, 2021 (85 FR 64708, 64679). 
For the CCR Action, facilities had to indicate their future plans to 
cease receipt of waste by April 11, 2021 (85 FR 53517).
---------------------------------------------------------------------------

    For control periods in 2030 and thereafter, the emissions budgets 
will be the amounts calculated for each state and noticed to the public 
roughly one year before the control period, using the dynamic budget-
setting methodology. In this manner, the stringency of the program will 
be secured and sustained in the dynamic budgets of this program, 
regardless of whatever EGU transition activities ultimately occur in 
this 2026-2029 transition period.

                Table I.B-1--Preset CSAPR NOX Ozone Season Group 3 State Emissions Budgets (tons) for 2023 Through 2029 Control Periods *
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                            2023 State      2024 State      2025 State      2026 State      2027 State      2028 State      2029 State
                  State                       budget          budget          budget         budget **       budget **       budget **       budget **
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................           6,379           6,489           6,489           6,339           6,236           6,236           5,105
Arkansas................................           8,927           8,927           8,927           6,365           4,031           4,031           3,582
Illinois................................           7,474           7,325           7,325           5,889           5,363           4,555           4,050
Indiana.................................          12,440          11,413          11,413           8,410           8,135           7,280           5,808
Kentucky................................          13,601          12,999          12,472          10,190           7,908           7,837           7,392
Louisiana...............................           9,363           9,363           9,107           6,370           3,792           3,792           3,639
Maryland................................           1,206           1,206           1,206             842             842             842             842
Michigan................................          10,727          10,275          10,275           6,743           5,691           5,691           4,656
Minnesota...............................           5,504           4,058           4,058           4,058           2,905           2,905           2,578
Mississippi.............................           6,210           5,058           5,037           3,484           2,084           1,752           1,752
Missouri................................          12,598          11,116          11,116           9,248           7,329           7,329           7,329
Nevada..................................           2,368           2,589           2,545           1,142           1,113           1,113             880
New Jersey..............................             773             773             773             773             773             773             773
New York................................           3,912           3,912           3,912           3,650           3,388           3,388           3,388
Ohio....................................           9,110           7,929           7,929           7,929           7,929           6,911           6,409
Oklahoma................................          10,271           9,384           9,376           6,631           3,917           3,917           3,917
Pennsylvania............................           8,138           8,138           8,138           7,512           7,158           7,158           4,828
Texas...................................          40,134          40,134          38,542          31,123          23,009          21,623          20,635
Utah....................................          15,755          15,917          15,917           6,258           2,593           2,593           2,593
Virginia................................           3,143           2,756           2,756           2,565           2,373           2,373           1,951
West Virginia...........................          13,791          11,958          11,958          10,818           9,678           9,678           9,678
Wisconsin...............................           6,295           6,295           5,988           4,990           3,416           3,416           3,416
                                         ---------------------------------------------------------------------------------------------------------------
    Total...............................         208,119         198,014         195,259         151,329         119,663         115,193         105,201
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Further information on the state-level emissions budget calculations pertaining to Table I.B-1 is provided in section VI.B.4 of this document as well
  as the Ozone Transport Policy Analysis Final Rule TSD. Further information on the 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 VI.B.9 of this document.
** As described in section VI of this document, the budget for these years will be subsequently determined and equal the greater of the value above or
  that derived from the dynamic budget methodology.

    The budget-setting methodology that the EPA will use to determine 
dynamic budgets for each control period starting with 2026 is an 
extension of the methodology used to determine the preset budgets and 
will be used routinely to determine 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 stringency of the dynamic emissions budgets 
will 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. As already noted, for the control 
periods in which both preset budgets and dynamic budgets are determined 
for a state (i.e., 2026 through 2029), the state's dynamic budget will 
apply only if it is higher than the state's preset budget. See section 
VI.B of this document for additional discussion of the EPA's method for 
adjusting emissions budgets to ensure elimination of significant 
contribution from EGU sources in the linked upwind states.
    In conjunction with the levels of the emissions budgets, the 
carryover of unused allowances for use in future control periods as 
banked allowances 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. 
Unrestricted banking of allowances allows what might otherwise be 
temporary surpluses of allowances in some individual control periods to 
accumulate into a long-term allowance surplus that reduces allowance 
prices and weakens the trading program's incentives to control 
emissions. To prevent this outcome, the EPA is also revising the Group 
3 trading program by adding provisions that establish a routine 
recalibration process for banked allowances using a target percentage 
of 21 percent for the 2024-2029 control periods and 10.5 percent for 
control periods in 2030 and later years.
    As an enhancement to the structure of the trading program 
originally promulgated in the Revised CSAPR Update, the EPA is also 
establishing backstop daily emissions rates for coal

[[Page 36664]]

steam EGUs greater than or equal to 100 MW in covered states. Starting 
with the 2024 control period, a 3-for-1 allowance surrender ratio 
(instead of the usual 1-for-1 surrender ratio) will apply to emissions 
during the ozone season from any large coal-fired EGU with existing SCR 
controls exceeding by more than 50 tons a daily average NOX 
emissions rate of 0.14 lb/mmBtu. The daily average emissions rate 
provisions will apply to large coal-fired EGUs without existing SCR 
controls starting with the second control period in which newly 
installed SCR controls are operational at the unit, but not later than 
the 2030 control period.
    The backstop daily emissions rates work in tandem with the ozone 
season emissions budgets to ensure the elimination of significant 
contribution as determined at Step 3 is maintained over time and more 
consistently throughout each ozone season. They will offer downwind 
receptor areas a necessary measure of assurance that they will be 
protected on a daily basis during the ozone season by more continuous 
and consistent 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.\23\ In 
addition to maintaining a mass-based seasonal requirement, this rule 
will achieve a much more consistent level of emissions control in line 
with our Step 3 determination of significant contribution while 
maintaining compliance flexibility consistent with that determination. 
These trading program improvements will promote consistent emissions 
control performance across the power sector in the linked upwind 
states, which protects communities living in downwind ozone 
nonattainment areas from exceedances of the NAAQS that might otherwise 
occur.
---------------------------------------------------------------------------

    \23\ 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 is including enforceable emissions control requirements 
that will apply during the ozone season (annually from May to 
September) for nine non-EGU industries in the promulgated FIPs to 
achieve the required emissions reductions in 20 states with remaining 
interstate transport obligations for the 2015 ozone NAAQS in 2026: 
Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, and West Virginia. These 
requirements would apply to all existing emissions units and to any 
future emissions units constructed in the covered states that meet the 
relevant applicability criteria. Thus, the emissions limitations for 
non-EGU sources and associated compliance requirements would apply in 
all 20 states listed in this paragraph, even if some of these states do 
not currently have any existing emissions units meeting the 
applicability criteria for the identified industries.
    Based on our evaluation of the time required to install controls at 
the types of non-EGU sources covered by this rule, the EPA has 
identified the 2026 ozone season as a reasonable compliance date for 
industrial sources. The EPA is therefore finalizing control 
requirements for non-EGU sources that take effect in 2026. However, in 
recognition of comments and additional information indicating that not 
all facilities may be capable of meeting the control requirements by 
that time, the final rule provides a process by which the EPA may grant 
compliance extensions of up to 1 year, which if approved by the EPA, 
would require compliance no later than the 2027 ozone season, followed 
by an additional possible extension of up to 2 more years, where 
specific criteria are met. For sources located in the 20 states listed 
in the previous paragraph, the EPA is finalizing the NOX 
emissions limits listed in Table I.B-2 for reciprocating internal 
combustion engines in Pipeline Transportation of Natural Gas; the 
NOX emissions limits listed in Table I.B-3 for kilns in 
Cement and Cement Product Manufacturing; the NOX emissions 
limits listed in Table I.B-4 for reheat furnaces in Iron and Steel 
Mills and Ferroalloy Manufacturing; the NOX emissions limits 
listed in Table I.B-5 for furnaces in Glass and Glass Product 
Manufacturing; the NOX emissions limits listed in Table I.B-
6 for boilers in Iron and Steel Mills and Ferroalloy Manufacturing, 
Metal Ore Mining, Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, and Pulp, Paper, and Paperboard Mills; and the 
NOX emissions limits listed in Table I.B-7 for combustors 
and incinerators in Solid Waste Combustors or Incinerators.

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


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


[[Page 36665]]

    Based on evaluation of comments received, the EPA is not, at this 
time, finalizing the source cap limit as proposed at 87 FR 20046 (see 
section VII.C.2 of the April 6, 2022, Proposal).

 Table I.B-4--Summary of NOX Control Requirements for Iron and Steel and
                       Ferroalloy Emissions Units
------------------------------------------------------------------------
                                            NOX emissions standard or
             Emissions unit                   requirement (lb/mmBtu)
------------------------------------------------------------------------
Reheat furnace.........................  Test and set limit based on
                                          installation of Low-NOX
                                          Burners.
------------------------------------------------------------------------


 Table I.B-5--Summary of NOX Emissions Limits for Furnace Unit Types in
                  Glass and Glass Product Manufacturing
------------------------------------------------------------------------
                                             NOX emissions limit (lb/ton
                Furnace type                      of glass produced)
------------------------------------------------------------------------
Container Glass Manufacturing Furnace......                          4.0
Pressed/Blown Glass Manufacturing Furnace                            4.0
 or Fiberglass Manufacturing Furnace.......
Flat Glass Manufacturing Furnace...........                          7.0
------------------------------------------------------------------------


  Table I.B-6--Summary of NOX Emissions Limits for Boilers in Iron and
  Steel and Ferroalloy Manufacturing, Metal Ore Mining, Basic Chemical
   Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp,
                       Paper, and Paperboard Mills
------------------------------------------------------------------------
                                                    Emissions limit (lbs
                     Unit type                           NOX/mmBtu)
------------------------------------------------------------------------
Coal..............................................                  0.20
Residual oil......................................                  0.20
Distillate oil....................................                  0.12
Natural gas.......................................                  0.08
------------------------------------------------------------------------


     Table I.B-7--Summary of NOX Emissions Limits for Combustors and
         Incinerators in Solid Waste Combustors or Incinerators
------------------------------------------------------------------------
                                                     NOX emissions limit
    Combustor or incinerator, averaging period             (ppmvd)
------------------------------------------------------------------------
ppmvd on a 24-hour block averaging period.........                   110
ppmvd on a 30-day rolling averaging period........                   105
------------------------------------------------------------------------

    Section VI.C of this document provides an overview of the 
applicability criteria, compliance assurance requirements, and the 
EPA's rationale for establishing these emissions limits and control 
requirements for each of the non-EGU industries covered by the rule.
    The remainder of this preamble is organized as follows: section II 
of this document outlines general applicability criteria and describes 
the EPA's legal authority for this rule and the relationship of the 
rule to previous interstate ozone transport rulemakings. Section III of 
this document describes the human health and environmental challenges 
posed by interstate transport contributions to ozone air quality 
problems, as well as the EPA's overall approach for addressing 
interstate transport for the 2015 ozone NAAQS in this rule. Section IV 
of this document describes the Agency's analyses of air quality data to 
inform this rulemaking, including descriptions of the air quality 
modeling platform and emissions inventories used in the rule, as well 
as the EPA's methods for identifying downwind air quality problems and 
upwind states' ozone transport contributions to downwind states. 
Section V of this document describes the EPA's approach to quantifying 
upwind states' obligations in the form of EGU NOX control 
stringencies and non-EGU emissions limits. Section VI of this document 
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 VII of this document discusses 
the environmental justice analysis of the rule, as well as outreach and 
engagement efforts. Section VIII of this document describes the 
expected costs, benefits, and other impacts of this rule. Section IX of 
this document provides a summary of changes to the existing regulatory 
text applicable to the EGUs covered by this rule; and section X of this 
document discusses the statutory and executive orders affecting this 
rulemaking.

C. Costs and Benefits

    A summary of the key results of the cost-benefit analysis that was 
prepared for this final 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 
recommended by OMB's Circular A-4, of the health and climate benefits, 
compliance costs, and net benefits of the final rule, in 2016 dollars, 
discounted to 2023. The estimated monetized net benefits are the 
estimated monetized benefits minus the estimated monetized costs of the 
final rule. These results present an incomplete overview of the effects 
of the rule because important

[[Page 36666]]

categories of benefits--including benefits from reducing 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 rule to be 
more net beneficial than this table reflects.

Table I.C-1--Estimated Monetized Health and Climate Benefits, Compliance
      Costs, and Net Benefits of the Final Rule, 2023 Through 2042
                [Millions 2016$, discounted to 2023] \a\
------------------------------------------------------------------------
                                            3% Discount     7% Discount
                                               rate            rate
------------------------------------------------------------------------
Present Value:
    Health Benefits \b\.................        $200,000        $130,000
    Climate Benefits \c\................          15,000          15,000
    Compliance Costs \d\................          14,000           9,400
    Net Benefits........................         200,000         140,000
Equivalent Annualized Value:
    Health Benefits.....................          13,000          12,000
    Climate Benefits....................             970             970
    Compliance Costs....................             910             770
    Net Benefits........................          13,000          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 ozone and
  PM2.5 concentrations. The health benefits are associated with two
  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.
\c\ Climate benefits are calculated using four different estimates of
  the social cost of carbon (SC-CO2 (model average at 2.5 percent, 3
  percent, and 5 percent discount rates; 95th percentile at 3 percent
  discount rate). For presentational purposes in this table, the climate
  benefits associated with the average SC-CO2 at a 3-percent discount
  rate are used in the columns displaying results of other costs and
  benefits that are discounted at either a 3-percent or 7-percent
  discount rate.
\d\ The costs presented in this table are consistent with the costs
  presented in Chapter 4 of the Regulatory Impact Analysis (RIA). To
  estimate these annualized costs for EGUs, the 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
  percent real discount rate consistent with the rate used in IPM's
  objective function for cost-minimization. For further information on
  the discount rate use, please see Chapter 4, Table 4-8 in the RIA.

    As shown in Table I.C-1, the PV of the monetized health benefits, 
associated with reductions in ozone and PM2.5 concentrations, of this 
final rule, discounted at a 3-percent discount rate, is estimated to be 
about $200 billion ($200,000 million), with an EAV of about $13 billion 
($13,000 million). At a 7-percent discount rate, the PV of the 
monetized health benefits is estimated to be $130 billion ($130,000 
million), with an EAV of about $12 billion ($12,000 million). The PV of 
the monetized climate benefits, associated with reductions in GHG 
emissions, of this final rule, discounted at a 3-percent discount rate, 
is estimated to be about $15 billion ($15,000 million), with an EAV of 
about $970 million. The PV of the monetized compliance costs, 
discounted at a 3-percent rate, is estimated to be about $14 billion 
($14,000 million), with an EAV of about $910 million. At a 7-percent 
discount rate, the PV of the compliance costs is estimated to be about 
$9.4 billion ($9,400 million), with an EAV of about $770 million.

II. General Information

A. Does this action apply to me?

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

                     Table II.A-1--Regulated Groups
------------------------------------------------------------------------
                     Industry group                            NAICS
------------------------------------------------------------------------
Fossil fuel-fired electric power generation.............          221112
Pipeline Transportation of Natural Gas..................            4862
Metal Ore Mining........................................            2122
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
Solid Waste Combustors and Incinerators.................          562213
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
rule. This table lists the types of entities that the EPA is now aware 
could potentially be regulated by this rule. Other types of entities 
not listed in the table could also be regulated. To determine whether 
your EGU entity is regulated by this rule, you should carefully examine 
the applicability criteria found in 40 CFR 97.1004, which are unchanged 
in this rule. If you have questions regarding the applicability of this 
rule to a particular entity, consult the person listed in the FOR 
FURTHER INFORMATION CONTACT section.

[[Page 36667]]

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 finds that 
emissions reductions are required from EGU and non-EGU sources in a 
total of 23 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 FIP 
requirements for 23 states: Alabama, Arkansas, California, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, West Virginia, and Wisconsin.
    The EPA is revising the existing CSAPR Group 3 Trading Program to 
include additional states beginning in the 2023 ozone season. EGUs in 
three states not currently covered by any CSAPR trading program for 
seasonal NOX emissions--Minnesota, Nevada, and Utah--will be 
added to the CSAPR Group 3 Trading Program under this rule. EGUs in 
twelve states currently participating in the Group 3 Trading Program 
will remain in the program under this rule: Illinois, Indiana, 
Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, 
Pennsylvania, Virginia, and West Virginia. EGUs in seven states 
(Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Texas, and 
Wisconsin) will transition from the CSAPR Group 2 Trading Program to 
the CSAPR Group 3 Trading Program under this rule beginning in the 2023 
ozone season. The EPA is establishing 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 is establishing 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 establishing a backstop daily emissions rate of 0.14 lb/mmBtu for 
coal-fired steam units greater than or equal to 100 MW in covered 
states. The backstop emissions rate will first apply in 2024 for coal-
fired steam sources with existing SCRs, and in the second control 
period in which a new SCR operates, but not later than 2030, for those 
currently without SCRs.
    This rule establishes emissions limitations for non-EGU sources in 
20 states: Arkansas, California, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New 
Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia, 
and West Virginia. In these states, the EPA is establishing control 
requirements for the following unit types in non-EGU industries: 
reciprocating internal combustion engines in Pipeline Transportation of 
Natural Gas; kilns in Cement and Cement Product Manufacturing; reheat 
furnaces in Iron and Steel Mills and Ferroalloy Manufacturing; furnaces 
in Glass and Glass Product Manufacturing; boilers in Iron and Steel 
Mills and Ferroalloy Manufacturing, Metal Ore Mining, Basic Chemical 
Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp, 
Paper, and Paperboard Mills; and combustors and incinerators in Solid 
Waste Combustors and Incinerators. See Table II.A-1 in this document 
for a list of NAICS codes for each entity included for regulation in 
this rule.
    This rule reduces 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 air 
quality issues addressed by this rule are included in section III of 
this document.

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

    The statutory authority for this 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 rule. The 
most relevant portions of CAA section 110 are subsections 110(a)(1), 
110(a)(2) (including 110(a)(2)(D)(i)(I)) and 110(c)(1)).
    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.\24\ 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.\25\
---------------------------------------------------------------------------

    \24\ 42 U.S.C. 7410(a)(1).
    \25\ 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.\26\ 
It includes a list of specific elements that ``[e]ach such plan'' must 
address.\27\
---------------------------------------------------------------------------

    \26\ 42 U.S.C. 7410(a)(2).
    \27\ The 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 2 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.\28\
---------------------------------------------------------------------------

    \28\ 42 U.S.C. 7410(c)(1).
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    CAA section 110(a)(2)(D)(i)(I), also known as the ``good neighbor'' 
provision, provides the primary basis for this rule.\29\ 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].'' \30\ 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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    \29\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
    \30\ Id.

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[[Page 36668]]

    Once the EPA promulgates a NAAQS, the EPA must designate areas as 
being in ``attainment'' or ``nonattainment'' of the NAAQS, or 
``unclassifiable.'' CAA section 107(d).\31\ 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.\32\ In general, states with nonattainment areas 
classified as Moderate or higher must submit plans to the EPA to bring 
these areas into attainment according to the statutory schedule. CAA 
section 182.\33\ 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).\34\
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    \31\ 42 U.S.C. 7407(d).
    \32\ 42 U.S.C. 7511, 7511a.
    \33\ 42 U.S.C. 7511a.
    \34\ 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.\35\ Pursuant to this section, the 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 to make certain other changes to its 
regulations under 40 CFR parts 52, 75, 78, and 97, to effectuate the 
purposes of the Act. Such changes are discussed in section IX of this 
document.
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    \35\ 42 U.S.C. 7601(a)(1).
---------------------------------------------------------------------------

    Tribes are not required to submit state implementation plans. 
However, as explained in the 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 the EPA's approval of, an implementation 
plan. See 40 CFR 49.11(a); see also CAA section 301(d)(4).\36\ In the 
proposed rule, the EPA proposed an ``appropriate or necessary'' finding 
under CAA section 301(d) and proposed tribal FIP(s) as necessary to 
implement the relevant requirements. The EPA is finalizing these 
determinations, as further discussed in section III.C.2 of this 
document.
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    \36\ 42 U.S.C. 7601(d)(4).
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D. What actions has the EPA previously issued to address regional ozone 
transport?

    The EPA has issued several previous 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.\37\ 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.\38\ 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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    \37\ 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).
    \38\ ``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 the EPA's most recent trading programs are discussed in 
section VI.B.1.a of this document.
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    The EPA's next rule addressing the good neighbor provision, CAIR, 
was promulgated in 2005 and addressed both the 1997 fine particulate 
matter (PM2.5) NAAQS and 1997 ozone NAAQS.\39\ 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.\40\ On March 15, 
2006, the EPA promulgated FIPs to implement the emissions reductions 
required by CAIR.\41\ CAIR was remanded to EPA by the D.C. Circuit in 
North Carolina v. EPA, 531 F.3d 896 (D.C. Cir.), modified on reh'g, 550 
F.3d 1176 (D.C. Cir. 2008). 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.\42\
---------------------------------------------------------------------------

    \39\ 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).
    \40\ 70 FR 21147 (April 25, 2005).
    \41\ 71 FR 25328 (April 28, 2006).
    \42\ 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.\43\ 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.\44\ 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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    \43\ 76 FR 48208.
    \44\ CSAPR was revised by several rulemakings after its initial 
promulgation 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.\45\ However, this decision was reversed in April 2014 by 
the Supreme Court, which largely upheld the rule, including the 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

[[Page 36669]]

generally affirmed the EPA's interpretation of various statutory 
provisions and the 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 the 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.\46\
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    \45\ 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 the 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).
    \46\ 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.\47\ 
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.\48\ The EPA aligned the analysis and implementation of the 
CSAPR Update with the 2017 ozone season to assist downwind states with 
timely attainment of the 2008 ozone NAAQS.\49\ 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.
---------------------------------------------------------------------------

    \47\ 81 FR 74504.
    \48\ 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.
    \49\ 81 FR 74516. The 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. 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 2008 ozone NAAQS for 
20 of the 22 eastern states covered by the CSAPR Update.\50\
---------------------------------------------------------------------------

    \50\ Determination Regarding Good Neighbor Obligations for the 
2008 Ozone National Ambient Air Quality Standard, 83 FR 65878, 65882 
(December 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 
because 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.\51\
---------------------------------------------------------------------------

    \51\ Subsequently, the D.C. Circuit made clear in a decision 
reviewing the 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.\52\ 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 would 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 the 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 the EPA, would replace the Revised 
CSAPR Update FIP for that state.
---------------------------------------------------------------------------

    \52\ Revised Cross-State Air Pollution Rule Update for the 2008 
Ozone NAAQS, 86 FR 23054 (April 30, 2021).
---------------------------------------------------------------------------

    On March 3, 2023, the D.C. Circuit Court of Appeals denied the 
Midwest Ozone Group's (MOG) petition for review of the Revised CSAPR 
Update. MOG v. EPA, No. 21-1146 (D.C. Cir. March 3, 2023). The court 
noted that it has ``exhaustively'' addressed the interstate transport 
framework before, citing relevant cases, and ``incorporate them herein 
by reference.'' Slip Op. 1 n.1. In response to MOG's arguments, the 
court upheld the Agency's air quality analysis. Id. at 10-11. The court 
noted that in light of the statutory timing framework and court-ordered 
schedule the EPA was under, the Agency's methodological choices were 
reasonable and provided ``an appropriately reliable projection of air 
quality conditions and contributions in 2021.'' Id. at 11-12.

III. Air Quality Issues Addressed and Overall Rule Approach

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

[[Page 36670]]

level.\53\ 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).\54\ In general, areas that exceed the 
ozone standard are designated as nonattainment areas, pursuant to the 
designations process under CAA section 107(d), and are subject to 
heightened planning requirements depending on the severity of their 
nonattainment classification, see CAA sections 181, 182.
---------------------------------------------------------------------------

    \53\ 80 FR 65291.
    \54\ 40 CFR part 50, appendix P.
---------------------------------------------------------------------------

    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 Greenhouse Gas 
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.\55\ (80 FR 65300). The U.S. Global Change Research Program's 
Impacts of Climate Change on Human Health in the United States: A 
Scientific Assessment \56\ and Impacts, Risks, and Adaptation in the 
United States: Fourth National Climate Assessment, Volume II \57\ 
reinforced these findings. 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.58 59 60 Climate 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). The EPA 
responds to comments received on the impacts of climate change on ozone 
formation in section 11 of the Response to Comments (RTC) document.
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    \55\ 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. O3 by 
scenario and across models and years, within the overall signal of 
higher summer O3 concentrations in a warmer climate.
    \56\ U.S. Global Change Research Program (USGCRP), 2016: The 
Impacts of Climate Change on Human Health in the United States: A 
Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. 
Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. 
Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. 
Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, 
Washington, DC, 312 pp. https://dx.doi.org/10.7930/J0R49NQX.
    \57\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
    \58\ 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
    \59\ 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.
    \60\ 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
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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.\61\ 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.
---------------------------------------------------------------------------

    \61\ 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, in conjunction with variable 
meteorological conditions. 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 \62\ continue to show the importance of 
NOX emissions for ozone transport. This analysis is included 
in the docket for this rulemaking.
---------------------------------------------------------------------------

    \62\ Available in the docket for the October 2015 Revisions to 
the National Ambient Air Quality Standards for Ground-Level Ozone at 
https://www.regulations.gov/docket/EPA-HQ-OAR-2008-0699.
---------------------------------------------------------------------------

    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 of the 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.\63\
---------------------------------------------------------------------------

    \63\ 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, the 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

[[Page 36671]]

determined by the amount of VOC emissions.\64\ The EPA and others have 
long regarded NOX to be the more significant ozone precursor 
in the context of interstate ozone transport.\65\
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    \64\ ``Ozone Air Pollution.'' Introduction to Atmospheric 
Chemistry, by Daniel J. Jacob, Princeton University Press, 
Princeton, New Jersey, 1999, pp. 231-244.
    \65\ 81 FR 74514.
---------------------------------------------------------------------------

    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 rule. As described in section 
V.A of this document, 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 demonstrates that regional ozone concentrations 
affecting the vast majority of the downwind areas of air quality 
concern are NOX-limited, rather than VOC-limited. Therefore, 
the 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. The potential impacts of NOX 
mitigation strategies from other sources are discussed in section V.B 
of this document.
    In section V of this document, the 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 included in this rule will provide meaningful improvements 
in air quality at the downwind receptors. Based on the implementation 
schedule established in section VI.A of this document, the EPA finds 
that the regulatory requirements included in the 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 certain 
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 \66\ in the docket 
for this rulemaking for more information on the human health and 
ecosystem effects associated with ambient ozone exposure.
---------------------------------------------------------------------------

    \66\ Available at https://www.epa.gov/sites/default/files/2016-02/documents/20151001ria.pdf.
---------------------------------------------------------------------------

    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 
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 rule is an example of air 
pollution control actions implemented by the Federal Government in 
support of the more protective 2015 ozone NAAQS, and populations living 
in downwind ozone nonattainment and maintenance areas are expected to 
benefit from improved air quality that will result from reducing ozone 
transport. Further discussion of the environmental justice analysis of 
this rule is located in section VII of this document and in the 
accompanying regulatory impact analysis, titled ``Regulatory Impact 
Analysis for Final Federal Good Neighbor 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 subject rulemaking 
is to protect public health and the environment by eliminating 
significant contribution from 23 states to nonattainment or maintenance 
of the 2015 ozone NAAQS to meet the requirements of the CAA's 
interstate transport provision. In this 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.
    The EPA responds to other comments received on the health and 
environmental impacts of ozone exposure in section 11 of the RTC 
document.

B. Final 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 1998 NOX 
SIP Call and the 2005 CAIR. The Agency built upon this framework and 
further refined the methodology for addressing interstate transport 
obligations in subsequent rules such as CSAPR in 2011, the CSAPR Update 
in 2016, and the Revised CSAPR Update in 2021.\67\ In CSAPR, the EPA 
first articulated a ``4-step framework'' within which to assess 
interstate transport obligations for ozone. In this rule 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.
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    \67\ 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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    Comment: The EPA received comments supporting the Agency's use of 
the 4-step interstate transport framework as a permissible method for 
assigning the required amount of

[[Page 36672]]

emissions reductions necessary to eliminate upwind states' significant 
contribution. Commenters also noted that the 4-step interstate 
transport framework was reviewed by the Supreme Court in EPA vs. EME 
Homer City Generation, 572 U.S. 489 (2014), and upheld. However, other 
commenters took exception to the overall approach of this proposed 
action. These commenters alleged that the EPA is ignoring the 
``flexibility'' in addressing good neighbor obligations that it had 
purportedly suggested to states would be permissible in memoranda that 
the EPA issued in 2018. Commenters also raised concerns that the air 
quality modeling (2016v2) the EPA used to propose to disapprove SIP 
submittals and as the basis for the proposed FIP was not available to 
states at the time they made their submissions and that the changes in 
results at Steps 1 and 2 from prior rounds of modeling rendered the new 
modeling unreliable. Commenters also raised a number of arguments that 
the EPA should allow states an additional opportunity to submit SIPs 
before promulgating a FIP, advocated that the EPA should issue a ``SIP 
call'' under CAA section 110(k)(5), asked for the EPA to issue new or 
more specific guidance, or otherwise suggested that the EPA should 
defer acting to promulgate a FIP at this time.
    Response: As an initial matter, comments regarding the EPA's basis 
for disapproving SIPs are beyond the scope of this action.\68\ To the 
extent these comments relate to the legal basis for the EPA to 
promulgate a FIP, the EPA disagrees that it is acting in a manner 
contrary to the memoranda it released in 2018 related to good neighbor 
obligations for the 2015 ozone NAAQS. Arguments that the EPA must or 
should allow states to re-submit SIP submissions based on the most 
recent modeling information before the EPA promulgates a FIP ignore the 
plain language of the statute and relevant caselaw. CAA section 110(c) 
authorizes the EPA to promulgate a FIP ``at any time within 2 years'' 
of a SIP disapproval. No provision of the Act requires the EPA to give 
states an additional opportunity to prepare a new SIP submittal once 
the EPA has proposed a FIP or proposed disapproval of a SIP submittal. 
Comments regarding the timing of the EPA's actions and calls for the 
EPA to allow time for states to resubmit SIPs are further addressed in 
RTC sections 1.1 and 2.4.
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    \68\ We nonetheless further respond to comments regarding the 
timing and sequence of the EPA's SIP and FIP actions, the relevance 
of judicial consent decrees, the requests for a SIP call, and 
related comments--to the extent any of these issues are within scope 
of the present action--in Sections 1 and 2 of the RTC document 
located in the docket for this action.
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    With regard to the need for the EPA to develop and issue guidance 
in addressing good neighbor obligations, in EPA v. EME Homer City 
Generation, L.P., the Supreme Court held that ``nothing in the statute 
places the EPA under an obligation to provide specific metrics to 
States before they undertake to fulfill their good neighbor 
obligations.'' \69\ While we have taken a different approach in some 
prior rulemakings by providing states with an opportunity to submit a 
SIP after we quantified the states' budgets (e.g., the NOX 
SIP Call and CAIR \70\), the CAA does not require such an approach.
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    \69\ 572 U.S. 489, 510 (2014). ``Nothing in the Act 
differentiates the Good Neighbor Provision from the several other 
matters a State must address in its SIP. Rather, the statute speaks 
without reservation: Once a NAAQS has been issued, a State `shall' 
propose a SIP within three years, Sec.  [thinsp]7410(a)(1), and that 
SIP `shall' include, among other components, provisions adequate to 
satisfy the Good Neighbor Provision, Sec.  [thinsp]7410(a)(2).'' EPA 
v. EME Homer City Generation, L.P., 572 U.S. at 515.
    \70\ For information on the NOX SIP call see 63 FR 
57356 (October 27, 1998). For information on CAIR see 70 FR 25162 
(May 12, 2005).
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    2018 Memoranda. As commenters point out, the EPA issued three 
``memoranda'' in 2018 to provide some assistance to states in 
developing these SIP submittals.\71\ Each memorandum made clear that 
the EPA's action on SIP submissions would be through a separate notice-
and-comment rulemaking process and that SIP submissions seeking to rely 
on or take advantage of any so-called ``flexibilities'' in these 
memoranda would be carefully reviewed against the relevant legal 
requirements and technical information available to the EPA at the time 
it would take such rulemaking action. Further, certain aspects of 
discussions in those memoranda were specifically identified as not 
constituting agency guidance (especially Attachment A to the March 2018 
memorandum, which comprised an unvetted list of external stakeholders' 
ideas). And, although outside the scope of this action, as the EPA has 
explained in disapproving states' SIP submittals, those submittals did 
not meet the terms of the August 2018 or October 2018 memoranda 
addressing contribution thresholds and maintenance receptors, 
respectively.
---------------------------------------------------------------------------

    \71\ See Information on the Interstate Transport State 
Implementation Plan Submissions for the 2015 Ozone National Ambient 
Air Quality Standards under Clean Air Act Section 110(a)(2)(D)(i)(I) 
(March 27, 2018) (``March 2018 memorandum''); Analysis of 
Contribution Thresholds 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, August 31, 2018) (``August 2018 memorandum''); 
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''). These are available in the docket or at https://www.epa.gov/airmarkets/memo-and-supplemental-information-regarding-interstate-transport-sips-2015-ozone-naaqs.
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    Commenters mistakenly view Attachment A to the March 2018 
memorandum as constituting agency guidance. This memorandum was 
primarily issued to share modeling results for 2023 that represented 
the best information available to the Agency as of March 2018, while 
Attachment A then listed certain ideas from certain stakeholders that 
the EPA said could be further discussed among states and stakeholders. 
The EPA disagrees with commenters' characterization of the EPA's stance 
regarding these so-called ``flexibilities'' listed (without analysis) 
in Attachment A. The March 2018 memorandum provided, ``While the 
information in this memorandum and the associated air quality analysis 
data could be used to inform the development of these SIPs, the 
information is not a final determination regarding states' obligations 
under the good neighbor provision.'' The EPA again affirms that the 
concepts listed in Attachment A to the March 2018 memorandum require 
unique consideration, and these ideas do not constitute agency guidance 
with respect to transport obligations for the 2015 ozone NAAQS. 
Attachment A to the March 2018 memorandum identified a ``Preliminary 
List of Potential Flexibilities'' that could potentially inform SIP 
development. However, the EPA made clear in both the March 2018 
memorandum \72\ and in Attachment A that the list of ideas was not 
endorsed by the Agency but rather ``comments provided in various 
forums'' on which the EPA sought ``feedback from interested 
stakeholders.'' \73\ Further, Attachment A stated, ``EPA is not at this 
time making any determination that the ideas discussed below are 
consistent with the requirements of the CAA, nor are we specifically 
recommending that states use these approaches.'' \74\ Attachment A to 
the March 2018 memorandum, therefore, does not

[[Page 36673]]

constitute agency guidance, but was intended to generate further 
discussion around potential approaches to addressing ozone transport 
among interested stakeholders. The EPA emphasized in these memoranda 
that such alternative approaches must be technically justified and 
appropriate in light of the facts and circumstances of each particular 
state's submittal. To the extent states sought to develop or rely on 
one or more of these ideas in support of their SIP submissions, the EPA 
reviewed their technical and legal justifications for doing so.\75\
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    \72\ ``In addition, the memorandum is accompanied by Attachment 
A, which provides a preliminary list of potential flexibilities in 
analytical approaches for developing a good neighbor SIP that may 
warrant further discussion between EPA and states.'' March 2018 
memorandum at 1.
    \73\ March 2018 memorandum, Attachment A at A-1.
    \74\ Id.
    \75\ E.g., 87 FR 64423-64425 (Alabama); 87 FR 31453-31454 
(California); 87 FR 9852-9854 (Illinois); 87 FR 9859-9860 (Indiana); 
87 FR 9508, 9515 (Kentucky); 87 FR 9861-9862 (Michigan); 87 FR 9869-
9870 (Ohio); 87 FR 9798, 9818-9820 (Oklahoma); 87 FR 31477-31481 
(Utah); 87 FR 9526-9527 (West Virginia).
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    Regarding the October 2018 memorandum, that document recognized 
that states may be able to demonstrate in their SIPs that conditions 
exist that would justify treating a monitoring site as not being a 
maintenance receptor despite results from our modeling methodology 
identifying it as such a receptor. The EPA explained that this 
demonstration could be appropriate under two circumstances: (1) the 
site currently has ``clean data'' indicating attainment of the 2015 
ozone NAAQS based on measured air quality concentrations, or (2) the 
state believes there is a technical reason to justify using a design 
value from the baseline period that is lower than the maximum design 
value based on monitored data during the same baseline period. To 
justify such an approach, the EPA anticipated that any such showing 
would be based on an analytical demonstration that (1) meteorological 
conditions in the area of the monitoring site were conducive to ozone 
formation during the period of clean data or during the alternative 
base period design value used for projections; (2) ozone concentrations 
have been trending downward at the site since 2011 (and ozone precursor 
emissions of NOX and VOC have also decreased); and (3) 
emissions are expected to continue to decline in the upwind and 
downwind states out to the attainment date of the receptor. Although 
this is beyond the scope of this action, the EPA explained in its final 
SIP disapproval action that no state successfully demonstrated that one 
of these alternative approaches is justified. In this action, our 
analysis of the air quality data and projections in section IV of this 
document indicate that trends in historic measured data do not 
necessarily support adopting a less stringent approach for identifying 
maintenance receptors for purposes of the 2015 ozone NAAQS. In fact, as 
explained in section III.B.1.a and IV.D of this document, the EPA has 
found in its analysis for this final rule that, in general, recent 
measured data from regulatory ambient air quality ozone monitoring 
sites suggest that a number of receptors with elevated ozone levels 
will persist in 2023 even though our traditional methodology at Step 1 
did not identify these monitoring sites as receptors in 2023. Thus, the 
EPA is not acting inconsistently with that memorandum--the factual 
conditions that would need to exist for the suggested approaches of 
that memorandum to be applicable have not been demonstrated as being 
applicable or appropriate based on the relevant data.
    Regarding the August 2018 memorandum, as discussed in section 
IV.F.2 of this document, for purposes of Step 2 of our ozone transport 
evaluation framework, we are applying a 1 percent of NAAQS threshold 
rather than a 1 ppb threshold, as this memorandum had suggested might 
be appropriate for states to apply as an alternative. The EPA is 
finalizing its proposed approach of consistently using a 1 percent of 
the NAAQS contribution threshold at Step 2 to evaluate whether states 
are linked to downwind nonattainment and maintenance concerns for 
purposes of this FIP.
    The approach of this FIP ensures both national consistency across 
all states and consistency and continuity with our prior interstate 
transport actions for other NAAQS. Further, in this action the EPA is 
promulgating FIPs under the authority of CAA section 110(c). In doing 
so, the EPA has exercised its discretion to determine how to define and 
apply good neighbor obligations in place of the discretion states 
otherwise would exercise (subject to the EPA's approval as compliant 
with the Act). In general, the EPA is applying the 4-step interstate 
transport framework it devised over the course of its prior good 
neighbor rulemakings, including applying a consistent definition of 
nonattainment and maintenance-only receptors, and applying the 1 
percent of NAAQS threshold at Step 2. The basis for these decisions is 
further explained in sections IV.F.1 and IV.F.2 of the document. These 
policy judgments reflect consistency with relevant good neighbor case 
law and past agency practice implementing the good neighbor provision 
as reflected in the original CSAPR, CSAPR Update, Revised CSAPR Update, 
and related rulemakings. Nationwide consistency in approach is 
particularly important in the context of interstate ozone transport, 
which is a regional-scale pollution problem involving the collective 
emissions of many smaller contributors. Effective policy solutions to 
the problem of interstate ozone transport dating back to the 
NOX SIP Call (63 FR 57356 (October 27, 1998)) have 
necessitated the application of a uniform framework of policy 
judgments, and the EPA's framework applied here has been upheld as 
ensuring an ``efficient and equitable'' approach. See EME Homer City 
Generation, LP v. EPA, 572 U.S. 489, 519 (2014).
    Updated modeling. The EPA had originally provided 2023 modeling 
results in its March 2018 memorandum, which used a 2011-based platform. 
Many states used this modeling in providing good neighbor SIP 
submittals for the 2015 ozone NAAQS. While our action on the SIP 
submittals is not within scope of this action, commenters claim the use 
of new modeling or other information not available to states at the 
time they made their submittals renders this action promulgating a FIP 
unlawful. Notwithstanding whether that is an accurate characterization 
of the EPA's basis for disapproving the SIPs, we note that the court in 
Wisconsin rejected this precise argument against the CSAPR Update FIPs 
as a collateral attack on the SIP disapprovals. 938 F.3d at 336 (``That 
is the hallmark of an improper collateral attack. The true gravamen of 
the claim lies in the agency's failure to timely act upon the States' 
SIP submissions and, relatedly, its reliance on data compiled after the 
SIP action deadline. Both go directly to the legitimacy of the SIP 
denials.'').
    Nonetheless, we offer the following explanation of the evolution of 
the EPA's understanding of projected air quality conditions and 
contributions in 2023 resulting from the iterative nature of our 
modeling efforts. These modeling efforts are further addressed in 
section IV of this document. We acknowledge that to evaluate transport 
SIPs and support our proposed FIP the EPA reassessed receptors at Step 
1 and states' contribution levels at Step 2 through additional modeling 
(2016v2) before proposing this action and have reassessed again to 
inform the final action (2016v3). At proposal, we relied on CAMx 
Version 7.10 and the 2016v2 emissions platform to make updated 
determinations regarding which receptors would likely exist in 2023 and 
which states are projected to contribute above the contribution 
threshold to those receptors. As explained in the preamble of the EPA's 
proposed FIP and further detailed in the ``Air Quality

[[Page 36674]]

Modeling Technical Support Document for the Federal Implementation Plan 
Addressing Regional Ozone Transport for the 2015 Ozone National Ambient 
Air Quality Standards Proposed Rulemaking'' (Dec. 2021), hereinafter 
referred to as Air Quality Modeling Proposed Rule TSD, and the 
``Technical Support Document (TSD): Preparation of Emissions 
Inventories for the 2016v2 North American Emissions Modeling Platform'' 
(Dec. 2021), hereinafter referred to as the 2016v2 Emissions Inventory 
TSD, both available in the docket for this action (docket ID no. EPA-
HQ-OAR-2021-0668), this modeling built off of previous modeling 
iterations used to support the EPA's action on interstate transport 
obligations. The EPA periodically refines its modeling to ensure the 
results are as indicative as possible of air quality in future years. 
This includes making any necessary adjustments to our modeling platform 
and updating our emissions inventories to reflect current information, 
including information submitted during public comments on proposed 
actions.
    For this final rule, the EPA has evaluated a raft of technical 
information and critiques of its 2016v2 modeling provided by commenters 
on this action (as well as comments on the SIP actions) and has 
responded to those comments and incorporated updates into the version 
of the modeling used to support this final rule (2016v3). As explained 
in section IV.B of the document, in response to additional information 
provided by stakeholders following a solicitation of feedback during 
the release of the 2016v2 emissions inventory and during the comment 
periods on the proposed SIP actions, the EPA has reviewed and revised 
its 2016v2 modeling platform and input since the platform was made 
available for comment. The new modeling platform 2016v3 was developed 
from this input, and the modeling results using platform 2016v3 are 
available with this action. See section IV of this document for further 
discussion. Thus, the EPA's final rule is based on a comprehensive 
record of data and technical evaluation, including the updated modeling 
information used at proposal (2016v2), the comments received on that 
modeling, and the latest modeling used in this final rule (2016v3).
    The changes in projected outcomes at Steps 1 and 2 are a product of 
these changes; these updates between the data released in 2018 to now 
are an outgrowth of this iterative process, including updating the 
platform from a 2011 to a 2016 base year, updates to the emissions 
inventory information and other updates. It is reasonable for the 
Agency to improve its understanding of a situation before taking final 
action, and the Agency uses the best information available to it in 
taking this action.
    Further, these modeling updates have not uniformly resulted in new 
linkages--the 2016v2 modeling, for instance, corroborated the proposed 
approval of Montana and supported approval of Colorado's SIP in October 
of 2022.\76\ Although some commenters indicate that our modeling 
iterations have provided differing outcomes and are therefore 
unreliable, this is not what the overall record indicates. Rather, in 
general, although the specifics of states' linkages may have changed to 
some extent, our modeling on the whole has provided consistent outcomes 
regarding which states are linked to downwind air quality problems. For 
example, the EPA's modeling shows that most states that were linked to 
one or more receptors using the 2011-based platform (i.e., the March 
2018 data release) are also linked to one or more receptors using the 
newer 2016-based platform. Because the new platform uses different 
meteorology (i.e., 2016 instead of 2011), it is not unexpected that an 
upwind state would be linked to different receptors using 2011 versus 
2016 meteorology. In addition, although a state may be linked to a 
different set of receptors, those receptors are within the same areas 
that have historically had a persistent air quality problem. Only three 
upwind states included in the FIP went from being unlinked to being 
linked in 2023 between the 2011-based modeling provided in the March 
2018 memorandum and the 2016v3-based modeling--Alabama, Minnesota, and 
Nevada.
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    \76\ 87 FR 6095, 6097 at n. 15 (February 3, 2022) (Montana 
proposal); 87 FR 27050, 27056 (May 6, 2022) (Colorado, proposal), 87 
FR 61249 (October 11, 2022) (Colorado, final).
---------------------------------------------------------------------------

    Additionally, we disagree with commenters who claim that the 2016v2 
modeling results were sprung upon the states with the publication of 
the proposed SIP disapprovals. In fact, states had prior access to a 
series of data and modeling releases beginning as early as the 
publication of the 2016v1 modeling with the proposed Revised CSAPR 
Update in October 2020. States could have reviewed and used this 
technical information to understand and track how the EPA's modeling 
updates were affecting the list of potential receptors and linkages for 
the 2015 ozone NAAQS in the 2023 analytic year.
    The 2016-based meteorology and boundary conditions used in the 
modeling have been available through the 2016v1 platform, which was 
used for the Revised CSAPR Update (proposed, 85 FR 68964; October 30, 
2020). The updated emissions inventory files used in the current 
modeling were publicly released September 21, 2021, for stakeholder 
feedback, and have been available on our website since that time.\77\ 
The CAMx modeling software that the EPA used has likewise been publicly 
available for over a year before this final rule was proposed on April 
6, 2022. CAMx version 7.10 was released by the model developer, 
Ramboll, in December 2020. On January 19, 2022, we released on our 
website and notified a wide range of stakeholders of the availability 
of both the modeling results for 2023 and 2026 (including contribution 
data) along with many key underlying input files.\78\
---------------------------------------------------------------------------

    \77\ See https://www.epa.gov/air-emissions-modeling/2016v2-platform.
    \78\ See https://www.epa.gov/scram/photochemical-modeling-applications.
---------------------------------------------------------------------------

    By providing the 2016 meteorology and boundary conditions (used in 
the 2016v1 version) in fall of 2020, and by releasing updated emissions 
inventory information used in 2016v2 in September of 2021,\79\ we gave 
states and other interested parties multiple opportunities prior to 
proposal of this rule on April 6, 2022, to consider how our modeling 
updates could affect their status for purposes of evaluating potential 
linkages for the 2015 ozone NAAQS. In this final rule, we have updated 
our modeling to 2016v3, incorporating and reflecting the feedback and 
additional information we received through the multiple public comment 
opportunities the EPA made available on the 2016v2 modeling.
---------------------------------------------------------------------------

    \79\ https://www.epa.gov/air-emissions-modeling/2016v2-platform.
---------------------------------------------------------------------------

    The EPA's development of and reliance on newer modeling is 
reasonable and is simply another iteration of the EPA's longstanding 
scientific and technical work to improve our understanding of air 
quality issues and causes going back many decades.
    Comment: Commenters asserted that the EPA lacks authority under the 
good neighbor provision to do more than establish state-wide emissions 
budgets, which states may then implement through their own choice of 
emissions controls. The commenters claim that the EPA lacks authority 
to directly regulate emissions sources under the good neighbor 
provision, and they cite to case law that they view as establishing a 
``federalism bar'' to direct Federal regulation. Commenters assert that 
the

[[Page 36675]]

term ``amounts'' as used in the good neighbor provision prevents the 
agency from establishing emissions limits at individual sources, such 
as the non-EGU industrial units that the EPA proposed to regulate or 
implementing ``enhancements'' in its mass-based emissions trading 
approach for EGUs as it had proposed. Commenters claim these aspects of 
the rule are an unlawful or arbitrary and capricious departure from the 
EPA's prior transport rulemakings, which they claim only set mass-based 
emissions budgets as the means to eliminate ``significant 
contribution.''
    Response: To the extent these comments challenge the EPA's 
disapproval of states' 2015 ozone NAAQS good neighbor SIP submissions, 
they are out of scope of this action, which promulgates a FIP under the 
authority of CAA section 110(c)(1). To the extent commenters assert 
that the EPA does not have the authority to directly implement source-
specific emissions control requirements or other emissions control 
measures, means, or techniques, including emissions trading programs, 
in the exercise of that FIP authority, the EPA disagrees. While the 
courts have long recognized that the states have wide discretion in the 
design of SIPs to attain and maintain the NAAQS, see, e.g., Union 
Electric Co v. EPA, 427 U.S. 246 (1976), when the EPA promulgates a FIP 
to cure a defective SIP, the Act, including the definition of a FIP in 
section 302(y), provides for the EPA to directly implement the Act's 
requirements. The EPA is granted authority to choose among a broad 
range of ``emission limitations or other control measures, means, or 
techniques (including economic incentives, such as marketable permits 
or auctions of emissions allowances) . . . .'' CAA section 302(y); see 
also CAA section 110(a)(2) (empowering states to implement an identical 
set of emissions control mechanisms).
    The courts have also recognized that the EPA has broad authority to 
cure a defective SIP, that the EPA may exercise its own, independent 
regulatory authority in implementing a FIP in accordance with the CAA, 
and that the EPA in effect steps into the shoes of a state when it 
promulgates a FIP. See, e.g., Central Ariz. Water Conservation Dist. v. 
EPA, 990 F.2d 1531 (9th Cir. 1993); South Terminal Corp. v. EPA, 504 
F.2d 646 (1st Cir. 1974). Accord Virginia v. EPA, 108 F.3d 1397, 1406-
07 (D.C. Cir. 1997) (``The Federal Plan `provides an additional 
incentive for state compliance because it rescinds state authority to 
make the many sensitive and policy choices that a pollution control 
regime demands.''') (quoting Natural Resources Defense Council v. 
Browner, 57 F.3d 1122, 1124 (D.C. Cir. 1995)). Cf. District of Columbia 
v. Train, 521 F.2d 971 (D.C. Cir. 1975), vacated sub nom. EPA v. Brown, 
431 U.S. 99 (1977) (``[W]here cooperation [from states] is not 
forthcoming, we believe that the recourse contemplated by the commerce 
clause is direct federal regulation of the offending activity . . . 
.'').
    These same principles apply where the EPA must promulgate a FIP to 
address good neighbor requirements under CAA section 
110(a)(2)(D)(i)(I). The EPA has promulgated a series of FIPs in the 
past to address the relevant requirements for prior ozone and PM NAAQS. 
See, e.g., CAIR FIP, 71 FR 25328 (April 28, 2006); CSAPR, 76 FR 48208 
(August 8, 2011); the CSAPR Update, 81 FR 74504 (October 26, 2016); and 
the Revised CSAPR Update, 86 FR 23054 (April 30, 2021). Courts have 
upheld the EPA's exercise of this authority. See EME Homer City 
Generation v. EPA, 572 U.S. 489 (2014); Wisconsin v. EPA, 938 F.3d 303 
(D.C. Cir. 2019). Indeed, in EME Homer City, the U.S. Supreme Court 
held that the EPA is not obligated to provide guidance to states before 
acting on their good neighbor submissions or give states a second 
chance at correcting the deficiencies before promulgating a FIP, and 
the EPA may promulgate a FIP at any time after finalizing its 
disapproval of SIP submissions. 572 U.S. at 508-11.
    The cases cited by commenters, which they refer to as establishing 
the Train-Virginia federalism bar, were not reviewing the exercise of 
the EPA's authority in promulgating a FIP under CAA section 110(c)(1) 
but rather were describing the scope of the EPA's authority in acting 
on SIP submissions under CAA section 110(k)(3) or in issuing a ``SIP 
call'' under section 110(k)(5). In those latter contexts, the courts 
have held that the EPA may not dictate the specific control measures 
states must implement to meet the Act's requirements. See Virginia, 108 
F.3d at 1409-10. In Michigan, the D.C. Circuit upheld the EPA's 
exercise of CAA section 110(k)(5) authority in issuing the 
``NOX SIP Call,'' because, ``EPA does not tell the states 
how to achieve SIP compliance. Rather, EPA looks to section 
110(a)(2)(D) and merely provides the levels to be achieved by state-
determined compliance mechanisms. . . . However, EPA made clear that 
states do not have to adopt the control scheme that EPA assumed for 
budget-setting purposes.'' Michigan v. EPA, 213 F.3d 663, 687-88 (D.C. 
Cir. 2000).
    Commenters' position that the EPA must provide similar flexibility 
to the states in this action (i.e., only provide a general emissions 
reduction target and leave to states how to meet that target) is a non 
sequitur. The EPA is implementing a FIP in this action and must 
directly implement the necessary emissions controls. The EPA is not 
empowered to require states to implement FIP mandates. Such an approach 
would conflict with constitutional anti-commandeering principles, is 
not provided for in the Act, and would only constitute a partial 
implementation of FIP obligations in contravention of the holding in 
Wisconsin v. EPA, 938 F.3d at 313-20.
    Commenters' attempt to contrast the implementation of source-
specific emissions limitations at industrial sources with the 
establishment of a specific mass-based budget (as the EPA has set for 
power plants in prior good neighbor FIPs) is unavailing. CAA section 
110(c)(1) and 302(y) authorize the EPA in promulgating a FIP to 
establish ``enforceable emission limitations'' in addition to other 
types of control measures like mass-based trading programs. Further, in 
this action, the EPA has developed an emissions control strategy that 
prohibits the ``amount'' of pollution that significantly contributes to 
nonattainment and/or interferes with maintenance. We determine that 
amount, as we have in prior transport actions, at Step 3 of the 
analysis, by applying a multifactor analysis that includes considering 
cost and downwind air quality effects. See section V.A of this 
document. With the implementation of the selected controls (at Step 4) 
through both an emissions trading program for power plants and source-
specific emissions limitations for industrial sources, those 
``amounts'' that had been emitted prior to imposition of the controls 
will be eliminated.
    The Act does not mandate that the EPA must set a specific mass-
based budget for each state to eliminate significant contribution based 
on the use of the term ``amounts'' in CAA section 110(a)(2)(D)(i). As 
the Supreme Court recognized, the statute ``requires States to 
eliminate those `amounts' of pollution that `contribute significantly 
to nonattainment' in downwind States,'' and it delegates to states or 
EPA acting in their stead discretion to determine how to apportion 
responsibility among those upwind states. 572 U.S. at 514 (emphasis 
added). The statute does not define the term ``amount'' in the way 
commenters suggest (or in any other way), and neither the Agency nor 
any court has reached that conclusion. The

[[Page 36676]]

Supreme Court itself has recognized that the language of the good 
neighbor provision is amenable to different types of metrics for 
quantification of ``significant contribution.'' See EME Homer City 
Generation, L.P., 572 U.S. at 514 (``How is EPA to divide 
responsibility among the . . . States? Should the Agency allocate 
reductions proportionally . . ., on a per capita basis, on the basis of 
the cost of abatement, or by some other metric? . . . The Good Neighbor 
Provision does not answer that question for EPA.''); see also Michigan 
v. EPA, 213 F.3d 663, 677 D.C. Cir. 2000) (``Nothing in the text of . . 
. the statute spells out a criterion for classifying `emissions 
activity' as `significant.' ''); id. at 677 (``Must EPA simply pick 
some flat `amount' of contribution . . . ?''). When the State of 
Delaware petitioned the Agency under CAA section 126(b) to establish 
daily emissions rates for EGUs to remedy what it saw as continuing 
violations of the good neighbor provision for the 2008 ozone NAAQS, 
neither the EPA nor the reviewing court questioned whether the Agency 
had the statutory authority to do so. The EPA's decision not to was 
upheld on record grounds. See Maryland v. EPA, 958 F.3d 1185, 1207 D.C. 
Cir. 2020) (``In other words, Delaware's concern makes sense but has 
not been observed in practice.'').\80\
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    \80\ The Agency's view of the basis for backstop daily emissions 
rates for certain EGUs within the trading program has changed since 
the time of its action on Delaware's petition, as explained in 
section VI.B.
---------------------------------------------------------------------------

    The term ``amounts'' can be interpreted to refer to any number of 
metrics, and in fact the CAA uses the term in several contexts where it 
is clear Congress did not intend the term to refer to a fixed, mass-
based quantity of emissions. For example, in the definition of ``lowest 
achievable emission rate'' (LAER) in CAA section 171, the Act provides 
that the application of LAER shall not permit a proposed new or 
modified source to emit any pollutant in excess of ``the amount 
allowable under applicable new source standards of performance 
[NSPS].'' NSPS may be, and usually are, set as emissions standards or 
limitations that are rate- or concentration-based. See, e.g., 40 CFR 
part 60, subpart KKKK, table I (establishing concentration-based and 
rate-based emissions limits for stationary combustion turbines).\81\ 
Congress has elsewhere used the term ``amount'' in the CAA to refer to 
concentration-based standards. For example, in CAA section 163(b), 
Congress provided that maximum allowable increases in concentrations of 
certain pollutants ``shall not exceed the following amounts,'' with a 
list of allowable increases provided that are expressed in micrograms 
per cubic meter.\82\ As a third example, in the 1990 CAA Amendments, 
Congress provided that ozone nonattainment areas classified as Serious 
must provide a reasonable further progress demonstration of reductions 
in VOC emissions ``equal to the following amount,'' which is then 
described as a percentage reduction from baseline emissions. CAA 
section 182(c)(2)(B). These examples illustrate that the word 
``amounts'' is amenable to a variety of meanings depending on what is 
being measured or quantified. It would therefore be highly unlikely 
that Congress could have intended that ``amount'' as used in the good 
neighbor provision must signify only a fixed mass budget of emissions 
for each state expressed as total tons per ozone season.
---------------------------------------------------------------------------

    \81\ The EPA has interpreted the term ``amount'' as used in CAA 
section 111(a)(4) in the definition of the term ``modifications'' as 
an increase in a rate of emissions expressed as kilograms per hour. 
40 CFR 60.14(b).
    \82\ Notably, both the provisions of CAA section 171 and section 
163 given as examples here were added by the CAA Amendments of 1977, 
in the same set of amendments that Congress first strengthened the 
good neighbor provision and added the term ``amounts.'' See Public 
Law 95-95, 91 Stat. 685, 693, 732, 746.
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    Such an approach would, in fact, fail to address an important 
aspect of the problem of interstate transport. As explained in sections 
III.B.1.d, V.D.4, and VI.B.1, the EPA in this rule seeks to better 
address the need for emissions reductions on each day of the ozone 
season, reflecting the daily, but unpredictably recurring, nature of 
the air pollution problem, short-term health impacts, and the form of 
the 2015 ozone NAAQS, wherein nonattainment for downwind areas (and 
thus heightened regulatory requirements) could be based on ozone 
exceedances on just a few days of the year. The expression of the 
``amount'' of pollution that should be eliminated to address upwind 
states' ``significant contribution'' to that type of air pollution 
problem may appropriately take into account those aspects of the 
problem, and the EPA may appropriately conclude, as we do here, that a 
single, fixed, emissions budget covering an entire ozone season is not 
sufficient to the task at hand.
    In this action, the EPA reasonably applies the good neighbor 
provision, including the term ``amount,'' through the 4-step interstate 
transport framework. Under this approach, the EPA here, as it has in 
prior transport rulemakings for regional pollutants like ozone, 
identifies a uniform level of emissions reduction that the covered 
sources in the linked upwind states can achieve that cost-effectively 
delivers improvement in air quality at downwind receptors on a regional 
scale. The ``amount'' of pollution that is identified for elimination 
at Step 3 of the framework is therefore that amount of emissions that 
is in excess of the emissions control strategies the EPA has deemed 
cost-effective. Contrary to commenters' views, in prior transport rules 
utilizing emissions trading, the mass budgets through which the 
elimination of significant contribution was effectuated did not 
constitute the ``amounts'' to be eliminated but rather the residual 
emissions remaining following the elimination of significant 
contribution through the control stringency selected based on our 
multifactor assessment at Step 3. Nor did the EPA consider a mass-based 
budget to be the sole expression, even indirectly, of what constituted 
``significant contribution.'' See, e.g., CSAPR, 76 FR 48256-57 
(discussing the evaluation of the control strategies that would 
eliminate significant contribution for the 1997 ozone NAAQS, including 
combustion controls, and explaining, ``[I]t would be inappropriate for 
a state linked to downwind nonattainment or maintenance areas to stop 
operating existing pollution control equipment (which would increase 
their emissions and contribution).'').
    In other actions the EPA has taken to implement good neighbor 
obligations, the EPA has required or allowed for reliance on source-
specific emissions limitations rather than defining significant 
contribution as a mass-based budget. For example, the EPA imposed unit-
specific emissions limitations in granting a CAA section 126(b) 
petition from the State of New Jersey in 2011. Final Response to 
Petition From New Jersey Regarding SO2 Emissions From the 
Portland Generating Station, 76 FR 69052, 69063-64 (Nov. 7, 2011) 
(discussing the analytical basis for the establishment of emissions 
limits at specific units). This action was upheld by the Third Circuit 
in Genon Rema LLC v. EPA, 722 F.3d 513, 526 (3d. Cir. 2013).\83\
---------------------------------------------------------------------------

    \83\ In CAA section 126(c), Congress provided for the EPA to 
directly impose ``emission limitations'' to eliminate prohibited 
significant contribution. Notably, the statute affords the EPA and 
states flexibility in how an ``emissions limitation'' may be 
expressed, including as a ``quantity, rate, or concentration,'' see 
CAA section 302(k). It would make little sense that the EPA could 
only establish a mass-based definition of ``amounts'' under CAA 
section 110(a)(2)(D)(i)(I), when the statute provides for rate- or 
concentration-based limitations in CAA section 126, which directly 
incorporates 110(a)(2)(D)(i)(I). (In observing this, we do not 
concede that an ``emissions limitation'' itself could not also be 
expressed through a mass-based approach, which may be read as 
authorized by the term ``quantity,'' a term also used in CAA section 
302(k).)

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[[Page 36677]]

    Even where the EPA has provided for implementation of good neighbor 
requirements through mass-based budgets, it has recognized that other 
approaches may be acceptable as providing an equivalent degree of 
emissions reduction to eliminate significant contribution. See, e.g., 
NOX SIP Call, 63 FR 57378-79 (discussing approvability of 
rate-based emissions limit approaches for implementing NOX 
SIP Call and providing, ``the 2007 overall budget is an important 
accounting tool. However, the State is not required to demonstrate that 
it has limited its total NOX emissions to the budget 
amounts. Thus, the overall budget amount is not an independently 
enforceable requirement.''); CAIR, 70 FR 25261-62 (discussing ways 
states could implement CAIR obligations, including through emission-
rate limitations, so long as adequately demonstrated to achieve 
comparable reductions to CAIR's emissions budgets).
    Finally, as it has in its prior transport FIP actions, the EPA has 
in this action provided guidance for states on methods by which they 
could replace this FIP with SIPs, and in so doing, continues to 
recognize substantial state flexibility in achieving an equivalent 
degree of emissions reduction that would successfully eliminate 
significant contribution for the 2015 ozone NAAQS. See section VI.D of 
this document. While the EPA has exercised the responsibility it has 
under CAA section 110(c)(1) to step into the shoes of the covered 
states and directly implement good neighbor requirements through a 
particular set of regulatory mechanisms in this action, we anticipate 
that states may identify alternative, equivalent mechanisms that we 
would be bound to evaluate and approve if satisfactory, should states 
seek to replace this FIP with a SIP.
    For these reasons, the EPA disagrees with the contention that it is 
constrained by the good neighbor provision to define upwind state 
obligations solely by reference to a fixed, mass budget. We find it 
reasonable in this action to again determine the amount of 
``significant contribution'' at Step 3 by reference to uniform levels 
of cost-effective emissions controls that can be applied across the 
upwind sources. And, we find it appropriate to implement those 
emissions reductions at Step 4 through mechanisms that go beyond fixed, 
mass-based, ozone-season long budgets.
    The EPA's authority for its industrial source control strategies is 
further discussed in sections II.C. and III.B.1.c of this document. The 
relationship of the control strategy to the assessment of overcontrol 
is discussed in section V.D.4 of this document. The relationship of our 
FIP authority to state authorities and SIP calls under CAA section 
110(k)(5) is further discussed in RTC sections 1 and 2.
a. Step 1 Approach
    As proposed, the EPA applies the same basic method of the CSAPR 
Update and the Revised CSAPR Update for identifying nonattainment and 
maintenance receptors. However, we received comments arguing that the 
outcome of applying our methodology to identify receptors in 2023 
appears overly optimistic in light of current measured data from the 
network of ambient air quality monitors across the country. These 
commenters suggest that the EPA give greater weight to current measured 
data as part of the method for identifying projected receptors. As 
discussed further in section IV.D of this document, the EPA has 
modified its approach for identifying receptors for this final rule in 
response to these comments.
    This concern is more evident given that the 2023 ozone season is 
just a few months away, and the most recent measured ozone values in 
many areas strongly suggest that these areas will not likely see the 
substantial reduction in ozone levels that the 2016v2 and 2016v3 
modeling continue to project.
    It would not be reasonable to ignore recent measured ozone levels 
in many areas that are clearly not fully consistent with certain 
concentrations in the Step 1 analysis for 2023. Therefore, the EPA has 
developed an additional maintenance-only receptor category, which 
includes what we refer to as ``violating monitor'' receptors, based on 
current ozone concentrations measured by regulatory ambient air quality 
monitoring sites. We acknowledge that the traditional modeling plus 
monitoring methodology we used at proposal and in prior ozone transport 
rules would otherwise have identified such sites as being in attainment 
in 2023. Despite the implications of the current measured data 
suggesting there will be a nonattainment problem at these sites in 
2023, we cannot definitively establish that such sites will be in 
nonattainment in 2023 in light of our modeling projections. In the face 
of this uncertainty, we regard our ability to consider such sites as 
receptors for purposes of good neighbor analysis under CAA section 
110(a)(2)(D)(i)(I) to be a function of the requirement to prohibit 
emissions that interfere with maintenance of the NAAQS; even if our 
transport modeling projects that an area may reach attainment in 2023, 
we have other information indicating that there is an identified risk 
that attainment will not in fact be achieved in 2023. The EPA's 
analysis of these additional receptors further is explained in section 
IV.D of this document.
    However, because we did not identify this basis for receptor-
identification at proposal, in this final action we are only using this 
receptor category on a confirmatory basis. That is, for states that we 
find linked based on our traditional modeling-based methodology in 
2023, we find in this final analysis that the linkage at Step 2 is 
strengthened and confirmed if that state is also linked to one or more 
``violating monitor'' receptors. If a state is only linked to a 
violating-monitor receptor in this final analysis, we are deferring 
promulgating a final FIP (and we have also deferred taking final action 
on that state's SIP submittal). This is the case for the State of 
Tennessee. Among the states that previously had their transport SIPs 
fully approved for the 2015 ozone NAAQS, the EPA has also identified a 
linkage to violating-monitor receptors for the State of Kansas. The EPA 
intends to further review its air quality modeling results and recent 
measured ozone levels, and we intend to address these states' good 
neighbor obligations as expeditiously as practicable in a future 
action.
b. Step 2 Approach
    The EPA applies 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 in these 
rules as needing further evaluation of their good neighbor obligations 
to downwind states at Step 3.\84\ The EPA evaluated each state's 
contribution based on the average relative downwind impact calculated

[[Page 36678]]

over multiple days.\85\ States whose air quality impacts to all 
downwind receptors were below this threshold did not require further 
evaluation for measures 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 relatively low contribution 
screening threshold because many downwind ozone nonattainment and 
maintenance receptors receive transport contributions from multiple 
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 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 final rule, the EPA has updated 
the air quality modeling data used for determining contributions at 
Step 2 of the 4-step interstate transport framework using the 2016v3 
modeling platform. The EPA continues to find that this threshold is 
appropriate to apply for the 2015 ozone NAAQS. This rule's application 
of the Step 2 approach is comprehensively described in section IV of 
this document.
---------------------------------------------------------------------------

    \84\ For ozone, the impacts include those from VOC and 
NOX from all sectors.
    \85\ The number of days used in calculating the average 
contribution metric has historically been determined in a manner 
that is generally consistent with the 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, the 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).
---------------------------------------------------------------------------

    Many commenters challenged the use of a 1 percent of NAAQS 
threshold or otherwise raised issues with the EPA's Step 2 methodology. 
These comments are addressed in section IV.F of this document and in 
the RTC document.
c. Step 3 Approach
    The EPA continues to apply the same approach as the prior three 
CSAPR rulemakings for evaluating ``significant contribution'' at Step 
3.\86\ For states that are linked at Step 2 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.\87\
---------------------------------------------------------------------------

    \86\ For simplicity, the EPA (and courts) at times will refer to 
the Step 3 analysis as determining ``significant contribution''; 
however, the 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.''). See also EME Homer City, 795 F.3d 118, 136 
(upholding this approach to prong 2).
    \87\ EPA v. EME Homer City Generation, L.P., 572 U.S. 489 
(2014).
---------------------------------------------------------------------------

    In this action, the EPA applies 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. The 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 finalizes 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 finalizes 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 commensurate with the control strategy 
for EGUs.
    In CSAPR, the CSAPR Update, and the Revised CSAPR Update, the 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 the 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 rule, 
the 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 finds 
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 rule requires 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 V of this document.
    In this rule, the EPA also continues to apply its approach for 
assessing and avoiding ``over-control.'' In EME Homer

[[Page 36679]]

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 omitted).

    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 74551-52. See also 
Wisconsin, 938 F.3d at 325 (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 rule, and, as discussed in 
section V.D.4 of this document, does not find any over-control at the 
final control stringency selected.
    This evaluation of cost, NOX reductions, and air quality 
improvements, including consideration of whether there is proven over-
control, results in the 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.
    Comment: Commenters alleged that the EPA lacks authority to 
regulate EGUs under the good neighbor provision of the CAA, or at least 
in the manner proposed, because in their view, this regulation would 
intrude into areas of regulation that are reserved to other Federal 
agencies or are beyond the EPA's expertise. They focused in particular 
on the EGU trading program enhancements, which they alleged would 
threaten electric grid reliability, and asserted that EPA lacks 
authority or expertise to dictate the mix of electricity generation in 
the country.
    Response: The EPA disagrees that the regulation of EGUs in this 
action is unlawful or unsupported. The Agency has consistently and 
successfully regulated EGUs' ozone season NOX emissions 
under the good neighbor provision for over 25 years, beginning with the 
1997 NOX SIP Call. This action does not intrude on other 
Federal agencies' authorities and responsibilities with respect to 
managing the electric power grid and ensuring reliable electricity. 
While other agencies such as the Federal Energy Regulatory Commission 
(FERC) have primary responsibility for ensuring reliability of the bulk 
electric system, the EPA has ensured that its final rule here will not 
create electric reliability concerns. See section VI.B.1.d of this 
document. Thus, to the extent commenters are raising a record-based 
issue that the EPA through this action has created a reliability 
concern, we disagree. The EPA engaged in a series of stakeholder 
meetings with Reliability Coordinators who commented on the proposed 
rule, including several Regional Transmission Organizations (RTOs) as 
well as non-RTO entities throughout the rulemaking process.\88\
---------------------------------------------------------------------------

    \88\ See Documents no. EPA-HQ-OAR-2021-0668-0938, EPA-HQ-OAR-
2021-0668-0940, EPA-HQ-OAR-2021-0668-0941, EPA-HQ-OAR-2021-0668-
0942, EPA-HQ-OAR-2021-0668-0943, EPA-HQ-OAR-2021-0668-0944, and EPA-
HQ-OAR-2021-0668-0945 in the docket for this rulemaking.
---------------------------------------------------------------------------

    To the extent commenters maintain that--despite this record of 
collaboration and sensitivity to the need to ensure reliability in the 
implementation of its mandates, including in this rule--the EPA 
nonetheless fundamentally lacks authority to regulate the electric-
power sector in any way that ``impact[s] national electricity and 
energy markets,'' the EPA disagrees. The EPA has successfully regulated 
interstate ozone-precursor emissions from the power sector since the 
NOX SIP Call and the establishment of the NOX 
Budget Trading Program. See generally Michigan v. EPA, 213 F.3d 663 
(D.C. Cir. 2000); Appalachian Power Co. v. EPA, 249 F.3d 1032 (D.C. 
Cir. 2001). In fact, each of the EPA's interstate ozone transport 
rulemakings has focused on the regulation of ozone-precursor emissions 
from the power sector (all but the NOX SIP Call 
exclusively), because substantial, cost-effective reductions in ozone-
precursor emissions have been and continue to be available from fossil-
fuel fired EGUs. See, e.g., 63 FR 57399-400 (NOX SIP Call); 
70 FR 25165 and 71 FR 25343 (CAIR and CAIR FIP); 76 FR 48210-11 
(CSAPR); 81 FR 74507 (CSAPR Update); 86 FR 23061 (Revised CSAPR 
Update).\89\
---------------------------------------------------------------------------

    \89\ There are myriad other examples of effective power sector 
regulation under the CAA and other environmental statutes, including 
for example, new source performance standards (NSPS), best available 
retrofit technology (BART) requirements, and mercury and air toxics 
standards (MATS) under the CAA; effluent limitation guidelines 
(ELGs) under the Clean Water Act; and coal combustion residuals 
(CCR) requirements under the Resource Conservation and Recovery Act. 
Whether implemented through unit- or facility-level pollution 
control requirements or through emissions-trading or other market-
based programs, these regulations have been effective in reducing 
air and water pollution while not intruding into the regulatory 
arenas of other state and Federal entities. See Section 1 of the RTC 
for further discussion.
---------------------------------------------------------------------------

    This rule, like all prior EPA ozone-transport rulemakings, 
regulates only one aspect of the operation of fossil-fuel fired EGUs, 
that is, the emissions of NOX as an ozone-precursor 
pollutant during the ozone season. This rule limits EGU NOX 
emissions that interfere with downwind states' ability to attain and 
maintain the 2015 ozone NAAQS. The rule does not regulate any other 
aspect of energy generation, distribution, or sale. For these reasons, 
the rule does not intrude on FERC's power under the Federal Power Act, 
16 U.S.C. 791a, et seq. And, as in prior transport rules, the EPA 
implements this regulation through a proven, flexible mass-based 
emissions trading program that integrates well with, and in no way 
intrudes upon, the management of the power sector under other state and 
Federal authorities. This rule will not alter the procedures system 
operators employ to dispatch resources or force changes to FERC-
jurisdictional electricity markets, nor have commenters offered any 
explanation in this regard themselves.
    The actual compliance requirement that the EGUs must meet in the 
allowance trading system finalized here--just as in all prior 
interstate transport trading programs--is simply to hold sufficient 
allowances to cover emissions during a given control period, not to 
undertake any specific

[[Page 36680]]

compliance strategy.\90\ The owner or operator of an EGU has 
flexibility in determining how it will meet this requirement, whether 
through the add-on emissions controls that the EPA has selected in our 
Step 3 analysis, or through some other method or methods of compliance. 
The costs of meeting this allowance-holding requirement--just like the 
cost associated with meeting any other regulatory requirements--could 
possibly then be factored into what that unit bids in the wholesale 
electricity market (or in regulated jurisdictions, would factor into 
utility regulators' determinations of what can be cost-recovered).
---------------------------------------------------------------------------

    \90\ The EPA has included in this trading program certain 
``enhancements'' to ensure that the program continues to eliminate 
the emissions the EPA has determined constitute ``significant 
contribution'' over the entire life of the trading program. While 
one of the enhancements elevates a type of conduct that was already 
strongly discouraged into an enforceable violation, the other 
enhancements all simply modify the traditional allowance-based 
program structure to revise how the specific quantities of 
allowances that must be surrendered or the specific quantities of 
allowances available for surrender are determined. In finalizing 
this rule, the EPA has made a number of changes to its proposed 
enhancements to the trading program in response to comment and in 
part to ensure no impact on system reliability. Nonetheless, with 
these changes, the EPA has determined that the enhanced trading 
program can be implemented without impacting grid reliability. See 
section VI.B.1.d of this document.
---------------------------------------------------------------------------

    Those costs could, in turn, result in a reduction in electricity 
generation from higher-emitting sources and an increase in electricity 
generation from lower-emitting or zero-emitting generators, but that 
kind of generation shifting (not mandated but occurring as an economic 
choice by the regulated sources) is consistent, and in no way 
interferes with, the existing security-constrained economic dispatch 
protocols of the modern electrical grid. Further, this type of 
``impact'' on electricity markets--merely incidental, not mandated or 
even intended--is of the same type that results from any other kind of 
regulation, environmental or otherwise. Indeed, the U.S. Supreme Court 
recognizes that regulatory actions that may have some ``effect,'' or 
impact, in electricity markets do not on that basis alone intrude into 
authorities reserved to electricity rate-setting regulators by the 
Federal Power Act. See FERC v. Electric Power Supply Ass'n, 577 U.S. 
260, 282-84 (2016) (distinguishing between actions that have an effect 
on retail rates and actual intrusion into retail rate-setting itself); 
see also Hughes v. Talen, 578 U.S. 150, 166 (2016). The Supreme Court 
again recognized this distinction between ``incidental'' effects caused 
by lawfully issued environmental regulations and attempts to mandate a 
particular energy mix in West Virginia v. EPA. See 142 S. Ct. 2587, 
2613 n.4 (2022) (``[T]here is an obvious difference between (1) issuing 
a rule that may end up causing an incidental loss of coal's market 
share, and (2) simply announcing what the market share of coal, natural 
gas, wind, and solar must be . . . .'').
    This rule is squarely in the former camp; as the most stringent 
component of its emissions controls strategy for EGUs, the EPA has 
determined that to eliminate significant contribution to harmful levels 
of ozone in other states, certain fossil-fuel fired EGUs in ``linked'' 
upwind states that do not already have selective catalytic reduction 
(SCR) post-combustion control technology, should install it (or achieve 
emissions reductions commensurate with that technology). SCR is a well-
established at-the-source NOX control technology already in 
use by EGUs representing roughly 60 percent of the existing coal-fired 
generating capacity in the United States. This technology can be 
installed and operated to reduce NOX emissions without 
forcing the retirement or reduced utilization of any EGU. However, if 
market conditions are such that an EGU faced with this mandate (again, 
as expressed through an emissions trading budget) finds it more 
economic to comply with the mandate through the purchase of allowances, 
installation of other types of pollution control, reduced utilization, 
and/or retirement, rather than installing SCR technology, that is a 
choice that the EGU owner/operator can freely make under this rule.\91\ 
Security constrained economic dispatch is thereby maintained and is in 
no way interfered with.
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    \91\ As explained in section V.B of this document, the 
imposition of a backstop emissions rate beginning in 2030 for units 
that do not already have SCR installed could lead the owner of a 
given unit to decide that the unit's continued operation would be 
uneconomic without installation of SCR, but the establishment of 
technology-based emissions rates that require such decisions is 
consistent with decades of the EPA's rulemaking and permitting 
actions requiring source-specific pollution controls. Further, the 
backstop rate in this program is implemented through an enhanced 
allowance-surrender ratio, thus preserving some degree of 
flexibility through the emissions-trading program as the mechanism 
of compliance.
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    The EPA recognizes that cost to operate generators is one of the 
major factors that system operators utilize to determine ``merit'' 
order in dispatching resources. However, this rule does not intrude in 
any way into that process. To the extent that compliance with 
environmental regulations is a kind of cost that may need to be 
factored into generators' bids, this rule is no different than many 
other such requirements EGUs are already subject to. Further, as in 
prior transport rules, this rule applies a uniform control stringency 
to EGUs within the covered upwind states. EGUs that may have enjoyed a 
competitive advantage in the past through not bearing the costs of 
installing and running state-of-the-art emissions control technology 
now must bear that cost just as their competitors with that technology 
already are. Cf. EME Homer City, 572 U.S. 489, 519 (CSAPR is 
``[e]quitable 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.'').
    Finally, we note that this final rule does not include ``generation 
shifting'' as a component of the budget-setting process, even in the 
limited way that it had been used in prior transport rules like CSAPR 
and the CSAPR Update, i.e., to ensure the budget provided adequate 
incentive to ensure implementation of the selected emission-control 
strategy. See section V.B.1.f of this document. Further comments 
regarding legal authority for ``generation shifting,'' relationship to 
state authorities, and expertise associated with grid reliability are 
addressed in section 1.3 of the RTC. We further discuss our 
consideration of grid reliability concerns and adjustments in the 
approach to the EGU emissions trading program from proposal in section 
VI.B.1.d of this document.
    Comment: Commenters generally challenged the EPA's authority to 
establish emissions control requirements for non-EGU industrial sources 
in this action, or argued that such controls are unnecessary or 
unsupported, or run contrary to the EPA's prior actions under the good 
neighbor provision.
    Response: The states and the EPA have authority under CAA section 
110(a)(2)(D)(i)(I) to prohibit emissions from ``any source or other 
type of emissions activity'' that are found to significantly contribute 
to nonattainment or interfere with maintenance of the NAAQS in downwind 
states. This language is not limited only to power plant emissions, nor 
is it limited only to ``major'' sources or ``stationary'' sources. 
Thus, as a legal

[[Page 36681]]

matter, the emissions control requirements for certain large ``non-
EGU'' industrial sources in this action are grounded in unambiguous 
statutory authority, in particular the statute's use of the broad term 
``any source.'' Whereas the Act elsewhere includes definitions of 
``major stationary source,'' ``small source,'' and ``stationary 
source,'' see, e.g., CAA section 302(j), (x), and (z), no such 
qualifying terms are used with respect to the term ``any source'' at 
CAA section 110(a)(2)(D)(i). Rather, the scope of authority in this 
provision expands to encompass ``other type of emissions activity'' in 
addition to ``any source.'' The EPA has previously included non-EGU 
industrial sources in findings quantifying states' obligations under 
the good neighbor provision, in the 1998 NOX SIP Call, see 
63 FR 57365.\92\ See also Michigan v. EPA, 213 F.3d 663, 690-93 
(upholding the inclusion of certain non-EGU boilers in the 
NOX SIP Call). The EPA's determinations in prior transport 
rules not to regulate sources beyond the power sector were grounded in 
considerations not related to the Agency's statutory authority. For 
example, in the original CSAPR rulemaking, the EPA determined that the 
analytical effort needed to regulate non-EGU industrial sources would 
substantially delay the implementation of emissions reductions from the 
power sector. See, e.g., 76 FR 48247-48 (``[D]eveloping the additional 
information needed to consider NOX emissions from non-EGU 
source categories to fully quantify upwind state responsibility with 
respect to the 1997 ozone NAAQS would substantially delay promulgation 
of the Transport Rule. . . . [W]e do not believe that effort should 
delay the emissions reductions and large health benefits this final 
rule will deliver[.]''). The EPA acknowledged that by not addressing 
non-EGUs, it may not have promulgated a complete remedy to good 
neighbor obligations in CSAPR, id. at 48248. Nonetheless, the EPA went 
on to explain that there were limited emissions reductions available 
from non-EGUs at the cost thresholds the EPA determined would deliver 
substantial reductions from power plants. See id. at 48249 (the EPA's 
``preliminary assessment in the rule proposal suggested that there 
likely would be very large emissions reductions available from EGUs 
before costs reach the point for which non-EGU sources have available 
reductions . . . . EPA revisited these non-EGU reduction cost levels in 
this final rulemaking and verified that there are little or no 
reductions available from non-EGUs at costs lower than the thresholds 
that EPA has chosen . . . .''). The EPA noted in CSAPR that states 
retained the authority to regulate non-EGUs as a method of addressing 
their good neighbor obligations. Id. at 48320. The EPA also noted in 
CSAPR that ``potentially substantial'' non-EGU emissions reductions 
could be available in future rulemakings applying a higher cost 
threshold. See id. at 48256.
---------------------------------------------------------------------------

    \92\ Specifically, in the NOX SIP Call, the EPA set 
statewide budgets while states could determine which sectors to 
regulate. The EPA recommended that states regulate certain types of 
non-EGUs and quantified the statewide budgets based in part on the 
emissions reductions from those types of non-EGUs. In the parallel 
rule that followed under the EPA's CAA section 126(b) authority to 
directly regulate emissions to eliminate significant contribution, 
we promulgated an emissions trading program that would have included 
these same types of non-EGUs. Before this rule was implemented, all 
states adopted equivalent state trading programs using the 
NOX SIP Call model rule.
---------------------------------------------------------------------------

    Similarly, in the CSAPR Update, which addressed good neighbor 
obligations for the 2008 ozone NAAQS, the EPA found that regulation of 
non-EGUs was not warranted as the analysis required could delay the 
expeditious implementation of power plant reductions. The EPA found 
that the availability and cost-effectiveness of non-EGU reductions was 
uncertain and further analysis could delay implementation of the EGU 
strategy beyond 2017. The EPA acknowledged that it was not promulgating 
a complete remedy for good neighbor obligations for the 2008 ozone 
NAAQS and indicated its intention to further review emissions-reduction 
opportunities from non-EGU and EGU sources. 81 FR 74521-22.
    In Wisconsin, the court held that the EPA's deferral of a complete 
good neighbor remedy by 2017, on the basis, among other things, of 
uncertainty regarding non-EGU emissions reductions and the need for 
further regulatory analysis, was unlawful. 938 F.3d at 318-19. The 
court noted that `` `the statutes and common sense demand regulatory 
action to prevent harm, even if the regulator is less than certain.' '' 
Id. at 319 (quoting Ethyl Corp. v. EPA, 541 F.2d 1, 24-25 (D.C. Cir. 
1976)), and that agencies can only avoid meeting their statutory 
obligations where ``scientific uncertainty is so profound that it 
precludes EPA from making a reasoned judgment.'' Id. (citing 
Massachusetts v. EPA, 549 U.S. 497, 534 (2007)). Further, the court 
rejected the EPA's argument that it would have delayed its rulemaking 
if the EPA needed to complete a non-EGU analysis in a timely manner, 
holding that ``administrative infeasibility'' is not sufficient to 
``justify . . . noncompliance with the statute.'' Id. Rather, the 
Agency would need to ``meet the `heavy burden to demonstrate the 
existence of an impossibility.' '' Id. (quoting Sierra Club v. EPA, 719 
F.2d 436, 462 (D.C. Cir. 1983)).
    Following the remand of the CSAPR Update in Wisconsin, in the 
Revised CSAPR Update, the EPA conducted an analysis of non-EGUs to 
ensure it had implemented a complete remedy to eliminate significant 
contribution for the covered states for the 2008 ozone NAAQS. While 
acknowledging uncertainty in the datasets for non-EGUs, the EPA 
concluded: ``[U]sing the best information currently available to the 
Agency, . . . the EPA is concluding that there are relatively fewer 
emissions reductions available at a cost threshold comparable to the 
cost threshold selected for EGUs. In the EPA's reasoned judgment, the 
Agency concludes such reductions are estimated to have a much smaller 
effect on any downwind receptor in the year by which the EPA finds such 
controls could be installed.'' 86 FR 23059. Therefore, the EPA 
determined control of non-EGU emissions was not required to eliminate 
significant contribution for the 2008 ozone NAAQS.
    The circumstances that led the EPA to defer or decline regulation 
of non-EGU sources in CSAPR, the CSAPR Update, and the Revised CSAPR 
Update, are not present here, and the EPA's determination in this 
action that prohibiting certain emissions from certain non-EGU sources 
is necessary to eliminate significant contribution for the 2015 ozone 
NAAQS is a logical extension of the analyses and evolution of 
regulatory policy development spanning its prior good neighbor rules, 
now applied to implement this more protective NAAQS. As the EPA 
explained at proposal, unlike in CSAPR and the Revised CSAPR Update, in 
this action the EPA finds that available reductions and cost-levels for 
the non-EGU stringency are commensurate with the control strategy for 
EGUs. Following consideration of comments and after some adjustments in 
the non-EGU analysis and control strategy, in this final rule, the EPA 
continues to find this to be the case. See sections V.C and V.D of this 
document.
    In particular, the EPA continues to find that cost-effective 
emissions reductions are available for non-EGUs at a representative 
cost-threshold that is lower than the cost-threshold the EPA is 
applying for EGUs. See section V.C. of this document. These emissions 
control strategies are generally comparable to the emissions reduction 
requirements that similar sources in downwind states

[[Page 36682]]

are already required to meet. See section V.B.2 of this document. The 
EPA finds that the implementation of these emissions control strategies 
at non-EGUs, in conjunction with the strategies for EGU, will make a 
cost-effective and meaningful improvement in air quality through 
reducing ozone levels at the identified downwind receptors, and, 
therefore, the EPA has determined that these strategies will eliminate 
the amount of upwind emissions needed to address significant 
contribution under the good neighbor provision. The EPA's action here 
is focused on the most impactful industries and emissions units as 
determined by our evaluation of the power sector and the non-EGU 
screening assessment prepared for the proposal; indeed, of the 41 
industries, as identified by North American Industry Classification 
System codes, we analyzed, only nine industries met the criteria for 
further evaluation of significant contribution. See section V.B.2 of 
this document. Further, the EPA finds that these strategies do not 
result in ``overcontrol.'' See section V.D.4 of this document. As such, 
the EPA maintains that its final determinations regarding non-EGUs and 
its inclusion of non-EGU emissions sources within this final rule are 
statutorily authorized and lawful.\93\
---------------------------------------------------------------------------

    \93\ Certain changes in the emissions control strategies for 
non-EGUs reflecting comments and updated information are explained 
in section VI.C of this document.
---------------------------------------------------------------------------

    The EPA disagrees that it should defer regulation of industrial 
sources to the NSPS program under CAA section 111(b). CAA section 
111(b) does not expressly provide for the elimination of ``significant 
contribution'' as is required under CAA section 110(a)(2)(D)(i)(I). In 
particular, commenter's statement that NSPS rulemakings under section 
111(b) will appropriately address the emissions that we find must be 
eliminated in this action is not correct. Standards under section 
111(b) apply only to new and modified sources, not existing sources. 
This action, however, finds that reductions in ongoing emissions from 
existing sources are needed to eliminate significant contribution. An 
NSPS standard for new and modified sources would not address such 
emissions from existing sources. To the extent that covered sources in 
this action also may be covered by an older NSPS, these sources 
nonetheless continue to have emissions that the EPA finds significantly 
contribute and can be eliminated through further emissions control as 
determined in this action. We further disagree with commenter's 
separate suggestion that the EPA use section 111(b) and (d) to regulate 
both new and existing sources of ozone season NOX, which is 
premised on the incorrect notion that the EPA's action here is an 
attempt to regulate entire source categories nationwide, rather than to 
eliminate significant contribution pursuant to CAA section 
110(a)(2)(D)(i)(I). This action applies only to the extent a state is 
``linked'' to downwind receptors, and therefore this action only 
regulates covered non-EGU industrial sources in 20 states. Further, 
this comment ignores that the regulation of criteria pollutant 
emissions from existing sources under CAA section 111(d) is limited by 
the criteria pollutant exclusion in CAA section 111(d)(1)(A)(i).
    The EPA agrees with the commenters who assert that the EPA's 
authority to regulate non-EGUs under the good neighbor provision is 
well-grounded in administrative precedent and case law. Our previous 
discussion briefly recites several of the most salient aspects of that 
history. We also agree that the statutory language is not limited only 
to those sources that emit above 100 tons per year. The EPA's Step 3 
and Step 4 analyses in this regard, which establish certain thresholds 
based on historical actual emissions, potential to emit and/or metrics 
for unit design capacity, reflect a reasoned judgment by the Agency 
regarding which emissions can be cost-effectively eliminated to address 
significant contribution, under the facts and circumstances of this 
action. That these thresholds are designed to exclude certain smaller 
or lower-emitting units does not reflect a determination that the EPA 
lacks legal authority to regulate such sources under different facts 
and circumstances.
    The EPA identified two industry tiers of potential non-EGU 
emissions reductions in its non-EGU screening assessment at proposal, 
based on screening metrics intended to capture different kinds of 
impacts that non-EGU sources may have on identified receptors. The EPA 
agrees that it is only authorized to prohibit emissions under the good 
neighbor provision that significantly contribute to nonattainment or 
interfere with maintenance in downwind states, and we determined that 
these industries did so. The EPA sought comment on whether additional 
non-EGU industries significantly contributed to nonattainment or 
interfered with maintenance in downwind states. The EPA did not receive 
comments identifying other industrial stationary sources that are more 
impactful that should be regulated instead of those the EPA identified. 
We believed at proposal and confirm here in our final rule that the 
methodology used in the screening assessment comported with the factors 
that we consider at Step 3. Further, the EPA's 4-step interstate 
transport framework, including the Step 3 analysis and an overcontrol 
assessment, ensure that the emissions reductions achieved at each 
source covered by this rule are in fact justified as part of an 
overall, complete remedy to eliminate significant contribution for the 
covered states for the 2015 ozone NAAQS. The EPA has decided to 
finalize emissions limitations for all of the non-EGU industries, with 
some modifications from proposal reflecting public input, as discussed 
in section VI.C of this document. The Agency's authority to establish 
unit- and/or source-specific emissions limitations in exercising our 
FIP authority is further discussed in section III.B.1 of this document.
    Comment: Commenters raise additional issues with the overall 
approach of the rule at Step 3 to address significant contribution 
through our evaluation of EGU and non-EGU strategies through parallel 
but separate analyses. They stated that the EPA failed to establish 
that the identified non-EGU emissions reductions are needed to 
eliminate significant contribution. Commenters stated that the 
identified non-EGU emissions reductions are not impactful of air 
quality at receptors or that they are much less cost-effective than the 
EGU emissions reductions. Commenters stated that the EPA grouped all 
non-EGU emissions reductions together in making a cost-effectiveness 
determination that is only an average and ignores significant variation 
in costs associated with controls on different types of non-EGU 
emissions units. They also stated the EPA did not assess multiple 
control technologies in the way that it did for EGUs, and they argued 
there is great variation in the profile of non-EGU industries and 
emissions unit types in the different upwind states or that individual 
emissions units do not contribute to an out-of-state air quality 
problem at all. Commenters argued that certain non-EGU controls were 
not feasible, or that the EPA had applied a different standard for 
``feasibility'' for non-EGUs than it did for EGUs. Commenters stated 
that the EPA should have provided a mass-based trading option for non-
EGUs just as it had for EGUs. By contrast, other commenters supported 
the regulation of non-EGUs in this action as necessary to ensure a 
complete remedy to good neighbor obligations, since the statute is not 
limited to regulating power plants.

[[Page 36683]]

Some commenters further stated that EGUs should not face any further 
emissions reduction obligation because all cost-effective controls have 
already been identified through prior transport rules, and that any 
further regulation of EGUs would only lead to the retirement of coal 
plants, which they believe is the EPA's true objective. Finally, some 
commenters argued that the EPA had not ensured that it only regulated 
up to the minimum needed for downwind areas to come into attainment.
    Response: Issues related to the specific technical bases for the 
Agency's determinations of what emissions constitute ``significant 
contribution'' at Step 3 of the 4-step framework are addressed in 
section V of this document. Here, we evaluate commenters' more general 
assertions that this action addresses non-EGU or EGU emissions in an 
inconsistent way. First, the EPA agrees with commenters that the task 
of evaluating significant contribution from the non-EGU industries is 
complex compared to EGUs in light of the much greater diversity in 
industries and emissions unit types. This, however, is not a valid 
basis to avoid emissions control requirements on such sources if needed 
to eliminate significant contribution. In this respect, the EPA's 
analysis in this final rule is that the 4-step framework, as upheld by 
the Supreme Court in EME Homer City, can be adequately applied even to 
this more complex set of sources in a way that parallels the analysis 
previously conducted only for EGUs. This analysis relies on evaluation 
of uniform levels of control stringency across all upwind states to 
find a level of emissions control that is cost-effective and 
collectively delivers meaningful downwind air quality improvement. For 
non-EGUs, the EPA identified the most impactful industries and 
emissions unit types and evaluated emissions control strategies for 
these units that have been demonstrated or applied across many similar 
facilities and emissions units. The EPA has evaluated whether these 
strategies are cost-effective on a cost-per-ton basis, and in 
particular has compared these strategies to those selected for EGUs. 
This analysis is set forth in sections V and VI of this document and 
associated technical support documents.
    Commenter's statement that the establishment of a uniform level of 
control for each group of industrial units across the linked upwind 
states fails to assess with greater precision or define a state-
specific proportion of emissions reduction that is needed for each 
downwind receptor is effectively an attempt to relitigate EME Homer 
City. The Court in that case rejected that the EPA must define 
significant contribution by reference to a specific quantum of 
reductions that each state must achieve that is proportional to its 
impact at a downwind receptor. The Court agreed with the EPA's concerns 
as to why that approach would be problematically complicated or even 
impossible to apply in light of the complex set of linkages among 
states for a regional pollutant like ozone. See 572 U.S. at 515-17. The 
Court found that the use of uniform cost thresholds to allocate 
responsibility for good neighbor obligations to be efficient and 
equitable, in that it requires those sources that have done less to 
reduce their emissions to come up to a minimum level of performance to 
what other sources are already achieving. Id. at 519. The EPA's 
analysis in this action in section V of this document establishes that 
this continues to be an appropriate means of delivering meaningful air 
quality improvement to downwind receptors, taking into consideration 
the complexities of interstate pollution transport.
    Not every upwind state has the same mix of non-EGU industries and 
emissions unit types, and it is also the case that the costs for 
installation of the selected level of control technology will vary from 
facility to facility based on site-specific considerations. This is 
also true for the set of EGU sources regulated here and in previous 
CSAPR rulemakings. These real-world complexities do not obviate the 
broader policy and technical judgements that the EPA makes at Step 3 
regarding what level of emissions control performance can be achieved 
on a region-wide basis to resolve significant contribution for a 
regional-scale pollutant like ozone. The EPA's design of cost 
thresholds derives from the identification of discrete types of 
NOX emissions control strategies. The EPA then identifies a 
representative cost-effectiveness on a per ton basis for that 
technology. In the Step 3 analysis, it is not the cost per ton value 
itself that is inherently meaningful, but rather how that cost-
effectiveness value relates to other control stringencies, how many 
emissions reductions may be obtained, and how air quality is ultimately 
impacted. The selected level of control stringency reflects a point at 
which further emissions mitigation strategies become excessively costly 
on a per-ton basis while also delivering far fewer additional emissions 
reductions and air quality benefits. This is often referred to as a 
``knee in the curve'' analysis. There are always inherent uncertainties 
in identifying a representative cost per ton value for any particular 
control stringency, but this in itself does not upset the EPA's ability 
to render an overall policy judgment based on the Step 3 factors as to 
a set of emissions control strategies that together eliminate 
significant contribution. See 86 FR 23054, 23073 (responding to similar 
comments on the Revised CSAPR Update).
    We note that the EPA has made a number of adjustments to the non-
EGU emissions limits identified at Step 4 to accommodate legitimate 
concerns regarding the ability of certain non-EGU facilities to meet 
the emissions control requirements that the EPA had proposed. The 
Agency's determinations regarding feasibility and installation timing 
for pollution controls are comparable and not inconsistent between EGUs 
and non-EGUs. The EPA is not establishing a trading program for non-
EGUs because the Agency does not have adequate baseline emissions data 
and information on monitoring currently at many of these emissions 
units to develop emissions budgets that could reliably implement the 
Step 3 determinations made in this action. However, for most of the 
non-EGU industries,\94\ the EPA is not mandating a specific control 
technology and is instead establishing numeric emissions limits that 
are uniform across the region and that allow sources to choose how to 
comply. The EPA's analysis, including review of RACT determinations, 
consent decrees, and permitting actions, shows that these emissions 
limits and control requirements are achievable by existing units in the 
non-EGU industries covered by this final rule. This rule will therefore 
bring all of these impactful industries and unit types across the 
region of linked upwind states up to this standard of performance, and 
thus will result collectively in a relatively substantial decrease in 
ozone-season NOX emissions, with associated reductions in 
ozone levels projected to result at the downwind receptors. This is 
further discussed in section V.D.
---------------------------------------------------------------------------

    \94\ For reheat furnaces in the Iron and Steel Mills and 
Ferroalloy Manufacturing industry, the EPA is establishing 
requirements to operate low-NOX burners achieving a 
specified level of emissions reduction; this approach is needed to 
allow for unit-specific testing before an appropriate emissions 
limitation can be set. See section VI.C.3 of this document.
---------------------------------------------------------------------------

    Some commenters alleged that the EPA's EGU control strategy goes 
beyond the cost-effectiveness determinations of prior transport rules, 
and they believe that the EPA's true objective is to force the 
retirement of coal plants. First, we note that the EGU emissions 
control strategy is premised entirely on at-the-

[[Page 36684]]

source emissions control technologies that are widely available and in 
use across the EGU fleet. It is not the EPA's intention in this rule to 
force the retirement of any EGU or non-EGU facilities or emissions 
units but to identify and eliminate significant contribution under CAA 
section 110(a)(2)(D)(i)(I) based on cost-effective and proven control 
technologies that are appropriate in relation to address the problem of 
interstate transport for the 2015 ozone NAAQS. Further, determinations 
of cost-effectiveness must be made in relation to the particular 
statutory provision and its purpose. The EPA recognized in CSAPR, for 
example, that additional emissions reductions beyond what were 
determined to be cost-effective in that action could be required to 
implement good neighbor obligations if a NAAQS were revised to a more 
protective level. See 76 FR 48210. Here it is not surprising that a 
more stringent level of control could be found justified in 
implementing transport obligations for the more protective 2015 ozone 
NAAQS. Those reductions are projected to deliver meaningful air quality 
improvement to downwind receptors, as discussed in section V.D of this 
document. Those air quality benefits continue to compare favorably to 
the air quality benefits that will be delivered through the combined 
non-EGU emissions limits, which apply to nine non-EGU industries (see 
section V.C of this document). We find that the implementation of both 
the EGU and non-EGU strategies identified in section V of this document 
together represent the appropriate level of emissions control 
stringency to eliminate significant contribution under CAA section 
110(a)(2)(D)(i)(I).
    Finally, the EPA also analyzed for overcontrol and does not 
identify any. Some commenters misstate the purpose of this rule as 
bringing downwind receptors into attainment. In line with the statutory 
directive in CAA section 110(a)(2)(D)(i)(I), this rule eliminates 
``significant contribution'' from upwind states; while the rule has 
substantial air quality benefits for downwind receptors, in many cases 
we project that a nonattainment or maintenance problem will continue to 
persist through 2023 and 2026 despite the emissions reductions achieved 
by this rule. Commenters alleging overcontrol have not met the 
requirement that overcontrol be established by particularized evidence 
through as-applied challenges. The Supreme Court has recognized that 
the EPA also has an obligation to avoid under-control and must have 
some leeway in fulfilling the good neighbor mandate of the Act given 
uncertainty in making forward projections of air quality and the 
efficacy or impact of emissions control determinations. See EME Homer 
City, 572 U.S. at 523. This is further addressed in section V.D.4 of 
this document.
d. Step 4 Approach
    The EPA is finalizing an approach similar to its prior transport 
rulemakings to implement the necessary emissions reductions through 
permanent and enforceable measures. The EPA is requiring EGU sources to 
participate in an emissions trading program and is making 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 is finalizing permanent and enforceable emissions rate limits 
and work practice standards, and associated compliance requirements, 
for several types of NOX-emitting combustion units across 
several industrial sectors. The measures for both EGUs and non-EGUs are 
required throughout the May 1-September 30 ozone season of each year. 
The EGU program will begin with the 2023 ozone season, and the non-EGU 
implementation schedule is targeted to the 2026 ozone season. Refer to 
section VI.A of this document for details on the implementation 
schedule.
    Based on the EPA's experience in implementing prior transport 
rulemakings, the Agency is making 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 in each control period 
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 the 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, the EPA is retaining 
an interstate trading program approach while making several 
enhancements to that approach.
    Thus, in this rulemaking, the EPA is including dynamic budget-
setting procedures in the regulations that will allow state emissions 
budgets for control periods in 2026 and later years to reflect more 
current data on the composition and utilization of the EGU fleet (e.g., 
the 2026 budgets will reflect recent data through 2024 data, the 2027 
budgets will reflect data through 2025, etc.). These enhancements will 
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 emissions controls in the 
latter years of the program. To provide greater certainty regarding the 
minimum quantities of allowances that will be available for compliance 
for the control periods in 2026 through 2029, the EPA is also 
establishing preset state emissions budgets for these control periods, 
and a dynamic state emissions budget determined for one of these 
control periods will apply only if it is higher than the state's preset 
budget for the control period.
    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 in power sector emissions to account for fluctuations 
in demand and EGU operations and is responsive to previous court 
decisions (see discussion in section VI.B.5 of this document). In this

[[Page 36685]]

action, the EPA is maintaining the existing assurance provisions that 
limit state emissions to levels below a percentage of the state's 
budget by requiring additional allowance surrenders in any instance 
where emissions in the state exceed the specified level, but with 
adjustments that allow the level to exceed 121 percent of a state's 
budget in a given control period if necessary to account for actual 
operational conditions in that control period. In addition, the EPA is 
also making 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 
certain units that contribute to exceedances of the assurance levels, 
to ensure EGU emissions control operation and associated air quality 
improvements. Implementation of the EGU emissions reductions using a 
CSAPR NOX trading program is further described in section 
VI.B of this document.
    In this rule, the EPA is also establishing emissions limitations 
for the non-EGU industry sources listed in Table II.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 finds that requiring NOX 
emissions reductions through emissions rate limits and control 
technology requirements for certain non-EGU industrial sources that the 
EPA found at Step 3 to be relatively impactful \95\ on downwind air 
quality is an effective strategy for reducing regional ozone transport. 
Therefore, the EPA is establishing 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 transport provision for the 
2015 ozone NAAQS.
---------------------------------------------------------------------------

    \95\ Section III of the Non-EGU Screening Assessment memorandum 
in the docket for this rulemaking describes the 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 finds 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 final rule. This is 
consistent with the 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 has 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). The EPA's approach of including new 
units in the NOX Budget Trading Program promulgated under 
the EPA's CAA section 126 authority was upheld by the D.C. Circuit in 
Appalachian Power v. EPA, 249 F.3d 1032 (2001). As the court noted, 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 is implementing the same court-affirmed 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.
    Comment: Commenters took issue with aspects of the EPA's proposed 
Step 4 approach. Commenters argued the EPA could not set unit- or 
source-specific emissions limits or other control requirements, for 
EGUs or non-EGUs. Commenters argued that various aspects of the non-EGU 
emissions control strategy would not be feasible for their facilities 
or were otherwise flawed. Many industrial-source and EGU commenters 
argued that the EPA had not provided sufficient time for sources to 
come into compliance. Commenters also challenged the EGU trading 
program ``enhancements'' as unnecessary or beyond the EPA's authority. 
In this regard, commenters argued that these changes deviated from the 
EPA's prior approach, were unnecessary overcontrol, constituted a 
command-and-control approach, could not be supported on the basis of 
environmental justice benefits, or were otherwise unlawful for other 
reasons. These commenters argue that the EPA's Step 4 dynamic budget 
approach for EGU regulation purportedly re-defines each state's 
``significant contribution'' annually and independent of any impact (or 
lack thereof) on air quality. They further argue that under this 
dynamic budgeting approach, even if a state eliminates the ``amount'' 
the EPA has identified as the state's significant contribution by 
respecting a given control period's emissions budget, sources within 
that state are expected to continue to make further reductions by 
operating their controls in a particular manner in subsequent control 
periods under potentially lower emissions budgets, which these 
commenters argue is inconsistent with case law on prior CSAPR rules.
    Response: Many of these comments regarding Step 4 issues are 
addressed elsewhere in this document or in the RTC document. The EPA's 
authority to establish unit- or source-specific emissions rates is 
addressed in section IV.B.1 of this document. Responses to comments and 
adjustments in the timing requirements of the final rule compared to 
proposal are discussed in VI.A. Responses to comments and adjustments 
in emissions control requirements for non-EGUs in the final rule 
compared to proposal are in section VI.C of this document.
    Responses to comments on the EGU trading program enhancements and 
adjustments in the final rule are contained in section VI.B of this 
document. However, here, in light of the changes in the emissions 
trading program for EGUs that we are finalizing in this action as 
compared to prior EGU emissions trading programs promulgated to address 
good neighbor obligations under other NAAQS, we set forth responses to 
comments specific to this topic.
    The EPA finds that these comments confuse Step 3 emissions 
reduction stringency determinations with Step 4 implementation program 
details. In this rulemaking's Step 3 analysis, the EPA is measuring 
emissions reduction potential from improving effective emissions rates 
across groups of EGUs adopting applicable pollution control measures 
and selecting a uniform control level whose effective emissions rates 
deliver an acceptable outcome under the multifactor test (including a 
finding of no overcontrol at the selected control stringency level). 
The ``amounts'' defined as significant contribution to nonattainment 
and interference with maintenance are

[[Page 36686]]

emissions that occur at effective emissions rates above the control 
stringency level selected at Step 3. That is, if a state's affected 
EGUs fail to reduce their effective emissions rates in line with the 
widely available and cost-effective control measures identified, they 
have therefore failed to eliminate their significant contribution to 
nonattainment and interference with maintenance of this NAAQS.
    In this rule, the EPA is finalizing several ``enhancements'' to its 
existing Group 3 emissions trading program for ozone season 
NOX, for reasons explained in section VI.B.1 of this 
document. In general, these changes will ensure that the emissions 
control program promulgated for EGUs at Step 4 of the EPA's 4-step 
interstate transport framework is in alignment with the emissions 
control stringency determinations the EPA made at Step 3. These 
enhancements reflect lessons learned through the EPA's experience with 
prior trading programs implemented under the good neighbor provision 
and ensure that the implementation of the elimination of significant 
contribution through an emissions trading program remains durable 
through a period of power sector transition. None of commenters' 
arguments against the EPA's authority to implement these enhancements 
are persuasive.
    First, the EPA is not mandating that any EGU must install SCR 
technology. All but one of the enhancements to the trading program 
continue to be implemented through allowance-holding requirements under 
the mass-based emissions budget and trading system, including the 
backstop rate. (The secondary emissions limitation, which is not 
implemented through allowance-holding requirements under the mass-based 
emissions budget and trading system, and which is discussed in section 
VI.B.1.c.ii of this document, merely establishes a stronger deterrent 
for a type of conduct that was already strongly discouraged under the 
pre-existing trading program regulations). Nonetheless, the EPA does 
have the authority to impose unit-specific emissions limits under the 
exercise of its FIP authority, and it has done so in this action for 
non-EGU industrial sources. This authority is distinct from the EPA's 
title I permitting authority as discussed by certain commenters, and 
the scope of that permitting authority is not relevant to this action.
    The quantification of emissions budgets in an allowance-based 
emissions trading program is one of multiple potential Step 4 
implementation program design choices that states and the EPA have 
authority to select in securing the emissions reductions deemed 
necessary under Step 3. See CAA section 110(a)(2)(A). The EPA and the 
states routinely determine control stringency on an emissions rate 
basis in line with demonstrated pollution control opportunities, and 
both the EPA and the states have implementation program design 
discretion to determine what compliance requirements, whether expressed 
on a rate, mass, concentration, or percentage basis, will assure an 
emissions performance that reflects the control stringency required. 
Dynamic budgets in the Step 4 implementation of this rule are simply to 
ensure the trading program continues to incentivize the implementation 
of the EGU control strategies we find are necessary to eliminate 
significant contribution at Step 3. The key distinction between dynamic 
budget approaches and preset budget approaches is not one in stringency 
or authority, but rather in timing and data resources for determining 
the suitable mass-based limits that are as well-matched as possible to 
expected emissions of the affected EGUs achieving the emissions rate-
based control stringency deemed necessary under Step 3 to eliminate 
significant contribution to nonattainment and interference with 
maintenance of the NAAQS.
    The EPA does not agree that the administrative mechanisms by which 
it will implement ``dynamic budgeting'' conflict with CAA section 
307(d) or the Administrative Procedure Act. The EPA is promulgating a 
complete FIP in this action, and the codified language of that FIP will 
not need to be modified as budgets are adjusted. This is because the 
FIP establishes the formula by which the budgets will be calculated 
each year (with preset budgets functioning as a floor from 2026 through 
2029). This is no different than how the EPA has implemented other 
calculations such as updating allocations using a rolling set of data 
in its prior CSAPR trading programs. See, e.g., 87 FR 10786. We view 
these actions as fundamentally ministerial in nature in that no 
exercise of Agency discretion is required. This process will rely on 
notices of availability of the relevant data in the Federal Register, 
coupled with an opportunity for the public to correct any errors they 
may identify in the data before the EPA sets each updated budget. See 
section VI.B.4 for more detail on how the EPA intends to implement 
dynamic budgeting. As in prior transport rules, this rule provides the 
opportunity for administrative appeal should an interested party 
identify some flaw in the EPA's updated data. See 40 CFR 78.1(b)(19)(i) 
(2023). That process is coupled with the availability of judicial 
review should the party remain dissatisfied with the EPA's resolution 
of complaints. See 40 CFR 78.1(a)(2) (requiring administrative 
adjudication as a prerequisite for judicial review). This 
administrative process has worked well throughout the history of 
implementing good neighbor trading programs under Part 97, and no such 
disputes have necessitated judicial resolution.
    Further, because the dynamic budgets simply implement the 
stringency level reflective of the emissions control performance the 
EPA has determined at Step 3 for the covered EGUs, the EPA does not 
agree that any ``potential variables'' that are unforeseeable now could 
upset the basis for the formula the EPA is establishing in this action. 
The EPA has adjusted the role of dynamic budgeting in this final rule 
as compared to the proposal. See sections VI.B.1 and VI.B.4 of the 
preamble. In particular, the EPA is applying an approach to budget 
setting through 2029 that will use the greater of either a preset 
budget based on information known to the Agency at the time of this 
action, or the dynamic budget to be calculated based upon future data 
yet to be reported. Thus, through 2029 the imposition of a dynamic 
budget would only increase rather than diminish the emissions allowed 
for that control period compared to the preset budgets established in 
this action. In addition, the EPA will determine each state's dynamic 
budget based on a rolling 3-year average of the state's heat input, 
thus smoothing out trends to account for interannual variability in 
demand and heat input and provide greater certainty and predictability 
as the budget updates from year to year.
    Moreover, the EPA does not agree that the EPA is constrained by the 
statute to only implement good neighbor obligations through fixed, 
unchanging, mass-based emissions budgets. See section III.B.1 of this 
document. The EPA finds good reason based on its experience with 
trading programs using fixed budgets why this approach does not 
necessarily ensure the elimination of significant contribution in 
perpetuity. The EPA has already once adjusted its historical approach 
to better account for known, upcoming changes in the EGU fleet to 
ensure mass-based emissions budgets adequately incentivize the control 
strategy determined at Step 3. This adjustment was introduced in the 
Revised CSAPR Update. See 82 FR

[[Page 36687]]

23121-22.\96\ The EPA now believes it is appropriate to ensure in a 
more comprehensive manner, and in perpetuity, that the mass-based 
emissions budget incentivize continuing implementation of the Step 3 
control strategies to ensure significant contribution is eliminated in 
all upwind states and remains so. The dynamic budget-setting process 
preserves these incentives over time by calculating the state emissions 
budgets for each future control period so as to reflect the Step 3 
control stringency finalized in this rule as applied to the most 
current information regarding the composition of the power sector in 
the control period. This is fully analogous in material respect to an 
approach to implementation at Step 4 that relies on application of 
unit-specific emissions rates that apply in perpetuity. The 
availability of unit-specific emissions rates as a means to eliminate 
significant contribution is discussed in further detail in section 
III.B.1 of this document. The EPA also explained this in the proposal. 
See 87 FR 20095-96. The EPA does not agree that either dynamic 
budgeting or the backstop rate results in overcontrol. See section 
V.D.4 of this document.
---------------------------------------------------------------------------

    \96\ Further, in the Revised CSAPR Update, the EPA acknowledged 
that a mechanism like dynamic budgeting could be appropriate for a 
transport rule with longer time horizons. We stated in response to 
comments that we were not ``in this action, including an adjustment 
mechanism to further adjust state emission budgets to account for 
currently unknown or uncertain retirements after the finalization of 
this rule . . . . EPA observes that the commenter's proposed 
mechanism would become increasingly valuable for rules where the 
timeframe extends further into the future where retirement 
uncertainty is higher.'' Revised CSAPR Update Response to Comments, 
EPA-HQ-OAR-2020-0272-219, at 153.
---------------------------------------------------------------------------

    The EPA is enhancing the trading program to help reconcile the 
approach of using mass-based budgets to achieve the elimination of 
significant contribution with the Wisconsin directive to provide a 
complete remedy under the good neighbor provision. This approach also 
better accords with ensuring measures to attain and maintain the NAAQS 
are permanent and enforceable. The dynamic budget approach recognizes 
that the uncertainty around future fleet conditions increases the 
further into the future one looks (and the EPA must look further under 
the ``full remedy'' directive). To preserve its ability to successfully 
implement its identified Step 3 stringency, the EPA is designing the 
implementation of this rule's emissions control program to benefit from 
the future availability of better data from the regulated sources to 
inform its application of its stringency measures identified in this 
rule.
    The EPA does not agree with commenters who suggest that these 
enhancements are undertaken for the purpose of a non-statutory 
``environmental justice'' objective. As explained in section VI.B of 
this document, certain enhancements to the trading program ensure that 
each EGU is adequately incentivized to continuously operate its 
emissions controls once those controls are installed. One commenter 
contends that the backstop emissions rate is not authorized based on 
environmental justice considerations, since it is not necessary and is 
overcontrol with respect to the EPA's statutory authority to address 
good neighbor obligations. But the EPA disagrees with the premise that 
these enhancements are unrelated to the statutory obligation to 
eliminate significant contribution. Taking measures to ensure that each 
upwind source covered by an emissions trading program to eliminate 
significant contribution is operating its installed pollution controls 
on a more continuous and consistent basis throughout the ozone season 
is entirely appropriate in light of the daily nature of the ozone 
problem, the impacts to public health and the environment from ozone 
that can occur through short-term exposure (e.g., over a course of 
hours), the fact that the 2015 ozone NAAQS is expressed as an 8-hour 
average, and that only a small number of days in excess of the ozone 
NAAQS are necessary to place a downwind area in nonattainment, 
resulting in continuing and/or increased regulatory burden on the 
downwind jurisdiction. See section III.A of this document.
    Further, the D.C. Circuit has held that the EPA must ensure that 
its good neighbor program has eliminated each state's sources from 
continuing to significantly contribute to nonattainment or interfere 
with maintenance in downwind states. See North Carolina, 531 F.3d at 
921. The commenters neglect to acknowledge the scenario that has 
frequently borne out in prior programs, in which future fleet changes 
that were not known at the time of initial setting of state emissions 
budgets produce unexpected ``hot air'' in the budget that, if 
unaccounted for, other units can exploit to forgo identified cost-
effective mitigation measures deemed necessary to eliminate significant 
contribution to nonattainment and interference with maintenance of the 
NAAQS.
    The EPA's experience is that fixed mass-based budgets that are 
determined based only on the profile of the power sector at the time 
the rule is promulgated, and without any additional requirement for 
pollution controls operation, can become quickly obsolete if the 
composition of the group of affected EGUs changes notably over time. As 
some sources retire, other sources relax their operation of 
NOX controls in response to a growing surplus of allowances, 
even though the EPA had concluded that ongoing operation of those 
controls is necessary to meet the statutory good neighbor requirements. 
For instance, under the CSAPR Update, in the 2018-2020 period, the 
fixed budget approach enabled large, frequently run units with existing 
SCR controls to not optimize those controls even though the EPA's 
assessment (as reflected in the CSAPR Update) was that the optimization 
of those controls was necessary to eliminate significant contribution. 
This deterioration in emission rate at SCR-controlled coal plants was 
widely observed across the CSAPR Update geography as the program 
advanced into later years and allowance price deteriorated. Whereas 
coal sources with SCR performed, on average, at a 0.086 lb/mmBtu rate 
in 2017, that same set of sources saw their environmental performance 
worsen to a 0.099 lb/mmBtu rate in 2020. A Congressional Research 
Service Report on EPA prior CSAPR trading programs indicated low prices 
observed in later years ``could lead to some decisions not to run some 
pollution controls at maximum output. This would, in turn, lead to 
higher emissions''.\97\
---------------------------------------------------------------------------

    \97\ Shouse, Kate. ``The Clean Air Act's Good Neighbor 
Provision: Overview of Interstate Air Pollution Control''. 
Congressional Research Services. August 30, 2018. Available at 
https://sgp.fas.org/crs/misc/R45299.pdf.
---------------------------------------------------------------------------

    In the case of individual units, this deterioration in performance 
can be quite pronounced and can occur as quickly as the second or third 
control period, as in the case of Miami Fort Unit 7 in Ohio in 2019, 
discussed in section V.B of this document. The absence of a sufficient 
incentive under the trading program to implement the identified control 
strategy at Step 3 can even result in collective emissions that exceed 
state-wide assurance levels. The EPA established these levels beginning 
with CSAPR, above which enhanced allowance-surrender requirements are 
triggered, in an effort to ensure sources in each state are held to 
eliminate their own significant contribution, which the D.C. Circuit 
has held is legally required, see North Carolina, 531 F.3d 896, 906-08 
(D.C. Cir. 2008). In four instances over the course of the 2019, 2020, 
and

[[Page 36688]]

2021 control periods under the CSAPR Update, sources in Mississippi and 
Missouri collectively exceeded their state-wide assurance levels in 
part due to deterioration in emissions performance that can be 
attributed to a glut of allowances within the CSAPR Update. See section 
VI.B.8 of the preamble.
    Thus, while this trading program structure may achieve some 
environmental benefit through fixed emissions budgets for initial 
control periods, over time those fixed budgets cease to have their 
intended effect, and remaining operating facilities can, and have, 
increased emissions or even discontinued the operation of their 
emissions controls. This, in turn, can lead to the continuation (or re-
emergence) of significant contribution in terms of a recurrence of 
excessive emissions that had been slated for permanent elimination 
under the EPA's determinations at Step 3. Although the EPA has always 
intended for its trading programs to provide flexibility, the Agency 
did not expect and has certainly never endorsed the use of that 
flexibility to stop the operation of controls that have already been 
installed. See, e.g., 76 FR 48256-57 (``[I]t would be inappropriate for 
a state linked to downwind nonattainment or maintenance areas to stop 
operating existing pollution control equipment (which would increase 
their emissions and contribution).''). Despite the EPA's expectations 
in CSAPR, the historical data establishes a real risk of ``under-
control'' if the existing trading framework is not improved upon. See 
EME Homer City, 572 U.S. at 523 (``[T]he Agency also has a statutory 
obligation to avoid `under-control,' i.e., to maximize achievement of 
attainment downwind.'').
    This result is also inconsistent with the statutory mandate to 
``prohibit'' significant contribution and interference with maintenance 
of the NAAQS in downwind 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 
to it.'' 42 U.S.C. 7426(c)(2) (emphasis added). See also North 
Carolina, 531 F.3d at 906-08 (each state must be held to the 
elimination of its own significant contribution). The purpose of the 
Agency's interstate trading programs under the good neighbor provision 
is to afford sources some flexibility in achieving region-wide 
emissions reductions; however, there is no justification that can be 
sustained within that framework for sources in certain areas within 
that region, or during periods of high ozone when good emissions 
performance is most essential, to emit at levels well in excess of the 
EPA's Step 3 determinations of significant contribution. Significant 
contribution, according to the statute, must be ``prohibited.'' CAA 
section 110(a)(2)(D)(i).
    Thus, these trading program enhancements are within the EPA's 
authority under CAA section 110(a)(2)(D)(i)(I) to eliminate interstate 
ozone pollution that significantly contributes to nonattainment or 
interferes with maintenance in downwind states. These enhancements 
ensure the elimination of significant contribution across all upwind 
states and throughout each ozone season. We observe in the Ozone 
Transport Policy Analysis Final Rule TSD, section E, that the trading 
program enhancements may also benefit underserved and overburdened 
communities downwind of EGUs in the covered geography of the final 
rule. See section VI.B of this document. This does not detract from the 
statutorily-authorized basis for these changes, and the EPA finds 
nothing impermissible in acknowledging the reality of these potential 
benefits for underserved and overburdened communities.
    The EPA appreciates a commenter's concern that our actions be 
legally defensible. The EPA acknowledges that the changes to the 
trading program structure for implementing good neighbor obligations 
discussed here constitute a change in the policy underlying its prior 
transport-rule trading programs for EGUs. However, the EPA is confident 
that these changes are in compliance with the holdings in judicial 
decisions reviewing prior transport rules. The fact that the EPA is 
making changes does not somehow render these enhancements legally 
impermissible or even subject to a heightened standard of review. See 
FCC v. Fox Television Stations, 556 U.S. 502, 514 (2009) (``We find no 
basis in the Administrative Procedure Act or in our opinions for a 
requirement that all agency change be subjected to more searching 
review.''). We have explained previously and elsewhere in the record 
that there are ``good reasons'' for the ``new policy.'' See id. at 515. 
And, we are of course fully aware that we have changed our position. 
See id. at 514-15. Specifically, we have gone from previously treating 
fixed, mass-based budgets as sufficient to eliminate significant 
contribution, to an approach for purposes of the 2015 ozone NAAQS 
reflecting a more nuanced understanding of how an emissions trading 
program that does not properly anticipate future fleet conditions at 
Step 4 may fail to achieve the elimination of emissions that should be 
prohibited based on our findings at Step 3. Further, we find there to 
be no ``serious reliance interests'' that have been or even could have 
been ``engendered'' by any prior policy on these issues, see id. at 
515-16. The EPA is implementing these enhancements for the first time 
with respect to a new obligation--good neighbor requirements for the 
2015 ozone NAAQS. No party reasonably could have invested substantial 
resources to-date to comply with an obligation that was heretofore 
undefined; and no commenter has supplied any information to the 
contrary.
2. FIP Authority for Each State Covered by the Rule
    On October 26, 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).\98\ 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 CAA 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 document.
---------------------------------------------------------------------------

    \98\ National Ambient Air Quality Standards for Ozone, Final 
Rule, 80 FR 65292 (Oct. 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 finalizing this FIP action now to address 23 states' 
good neighbor obligations for the 2015 ozone NAAQS.\99\ For each state 
for which the EPA is finalizing this FIP, the EPA either issued final 
findings of failure to submit or has issued a final disapproval of that 
state's SIP submission.
---------------------------------------------------------------------------

    \99\ The EPA notes that it is subject to, and has met through 
this action, a consent decree deadline to promulgate FIPs addressing 
2015 ozone NAAQS good neighbor obligations for the states of 
Pennsylvania, Utah, and Virginia. See Sierra Club et al. v. Regan, 
No. 3:22-cv-01992-JD (N.D. Cal. entered January 24, 2023).
---------------------------------------------------------------------------

    Several commenters asserted that the sequence of the EPA's actions, 
and in particular, the timing of its proposed FIP (which was signed on 
February 28,

[[Page 36689]]

2022, and published on April 6, 2022) in relation to the timing of its 
proposed SIP disapprovals (most of which were published on February 22, 
2022, four of which were published on May 24, 2022, and one of which 
was published on October 25, 2022), was either unlawful or unreasonable 
in light of the sequence of steps required under CAA section 110(k) and 
(c).
    These commenters are incorrect. As an initial matter, concerns 
about the timing or substance of the EPA's actions on the SIP 
submittals are beyond the scope of this action. Nor are the timing or 
contents of merely proposed actions to be considered final agency 
actions or subject to judicial review. See In re Murray Energy, 788 
F.3d 330 (D.C. Cir. 2015). With these principles in mind, the timing of 
this final action is lawful under the Act. First, 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.\100\ CAA section 110(c) authorizes the EPA to promulgate a FIP 
``at any time within 2 years'' of a SIP disapproval or making a finding 
of failure to submit. The Supreme Court recognized in EME Homer City 
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.'' \101\ Thus, the EPA may promulgate a FIP contemporaneously 
with or immediately following predicate final SIP disapproval (or 
finding no SIP was submitted). 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.
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    \100\ 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 the 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 the EPA's deadline to 
take final action on New York's SIP submission is extended to 
December 30, 2022. By stipulation of the parties, the December 15, 
2022, date in all three of these consent decrees was extended to 
January 31, 2023. By further stipulation of the parties in the 
Downwinders at Risk case, the January 31, 2023, date was further 
extended to December 15, 2023 for the EPA to act on the SIP 
submissions from the states of Arizona, Tennessee, and Wyoming.
    \101\ See EPA v. EME Homer City Generation, L.P., 572 U.S. 489, 
509 (2014) (citations omitted).
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    Second, and more importantly, the EPA has established predicate 
authority to promulgate FIPs for all of the covered states through its 
action with respect to the relevant SIP submittals. A brief history of 
these actions follows:
    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).\102\ Alabama subsequently withdrew its SIP 
submission and re-submitted a SIP submission on June 22, 2022. The EPA 
proposed to disapprove that SIP submittal on October 25, 2022.\103\ The 
EPA proposed to disapprove good neighbor SIP submissions for four 
additional states, California, Nevada, Utah, and Wyoming, on May 24, 
2022.\104\
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    \102\ 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).
    \103\ See 87 FR 64412.
    \104\ See 87 FR 31443 (California); 87 FR 31485 (Nevada); 87 FR 
31470 (Utah); 87 FR 31495 (Wyoming).
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    Subsequently, on January 31, 2023, the EPA Administrator signed a 
single disapproval action for all of the above states, with the 
exception of Tennessee and Wyoming.\105\ This action established the 
EPA's authority to promulgate FIPs for the disapproved states. (As 
explained in section IV.F of this document, the Agency is deferring 
action at this time for Tennessee and Wyoming with respect to its 
proposed FIP actions for those states. As discussed in section IV.F of 
this document, the EPA's most recent modeling and air quality analysis 
indicates that several states may be linked to downwind receptors for 
which we had not previously proposed disapproval or FIP action. The EPA 
anticipates addressing remaining interstate transport obligations for 
the 2015 ozone NAAQS for these in a subsequent rulemaking.)
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    \105\ See 88 FR 9336.
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    Additionally, the EPA has taken action that has triggered the EPA's 
obligation under CAA section 110(c) to promulgate FIPs addressing the 
good neighbor provision for several downwind 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.\106\ 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,\107\ the EPA currently has authority under the December 
5, 2019, findings of failure to submit to issue FIPs for New Mexico, 
Pennsylvania, Utah, and Virginia. In this final rule, the EPA is 
issuing FIP requirements for Pennsylvania, Utah, and Virginia.\108\
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    \106\ 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).
    \107\ 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).
    \108\ WildEarth Guardians v. Regan, No. 1:22-cv-00174 (D.N.M. 
entered Aug. 16, 2022); Sierra Club et al. v. EPA, No. 3:22-cv-01992 
(N.D. Cal. entered Jan. 24, 2023).
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    Further information on the procedural history establishing the 
EPA's authority for this final rule is provided in a document in the 
docket.\109\
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    \109\ See ``Final Rule: 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.'' This document updates a prior document of the same 
title provided at proposal (Document no. EPA-HQ-OAR-2021-0668-0131).

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[[Page 36690]]

    While the EPA's previous actions are sufficient to establish that 
the EPA's promulgation of this FIP action at this time is lawful, the 
timing of this action is all the more reasonable in light of the need 
for the EPA to address good neighbor obligations consistent with the 
rest of title I of the CAA. In particular, the D.C. Circuit in 
Wisconsin held that states and the 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).\110\ 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,\111\ which fell on August 3, 2021.\112\ As discussed in section 
VI.A of this document, by finalizing this action now, the EPA is able 
to implement initial required emissions reductions to eliminate 
significant contribution by the 2023 ozone season, which is the last 
full ozone season before the next attainment date, the Moderate area 
attainment date of August 3, 2024. The Wisconsin court emphasized that 
the 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 in alignment with the downwind attainment 
schedule, and that is precisely what the EPA is doing here.\113\ The 
EPA provides further response to the comments on this issue in section 
1 of the RTC document.
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    \110\ Wisconsin v. EPA, 938 F.3d 303, 313-14 (D.C. Cir. 2019) 
(citing North Carolina v. EPA, 531 F.3d 896, 911-13 (D.C. Cir. 
2008).
    \111\ Maryland v. EPA, 958 F.3d 1185, 1203-04 (D.C. Cir. 2020).
    \112\ 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).
    \113\ 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)).
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C. Other CAA Authorities for This Action

1. Withdrawal of Proposed Error Correction for Delaware
    The EPA proposed at 87 FR 20036 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 proposed to determine that the basis for the prior SIP 
approval was invalidated by the Agency's more recent technical 
evaluation of air quality modeling performed in support of the proposed 
rule,\114\ and that Delaware had unresolved interstate transport 
obligations for the 2015 ozone NAAQS. The EPA also proposed to issue a 
FIP for Delaware given these unresolved interstate transport 
obligations. However, based on the updated air quality modeling 
described in section IV.F. of this document and the technical 
assessment that informs this final rule, the EPA finds that Delaware is 
not projected to be linked to any downwind receptor above the 1 percent 
of the NAAQS threshold in 2023. Thus, based on the record before the 
Agency now, the original approval of Delaware's SIP submission was not 
in error, and the EPA is withdrawing its proposed error correction and 
proposed FIP for Delaware.
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    \114\ See the Air Quality Modeling Proposed Rule TSD in the 
docket for this rule.
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2. Application of Rule in Indian Country and Necessary or Appropriate 
Finding
    The EPA is finalizing its determination 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 final rule, as defined in 
this section. Certain areas of Indian country within the geography of 
the rule are or may be subject to state implementation planning 
authority. Other areas of Indian country within that geography are 
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.\115\ As described later, the EPA 
is including 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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    \115\ We note that, consistent with the 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 IV.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 IV.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 the 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.
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a. Indian Country Subject to Tribal Jurisdiction
    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 in this section) and other 
areas of Indian country over which the EPA or a tribe has demonstrated 
that a tribe has jurisdiction--the EPA here makes 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 will be 
referred to as the CAA section 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.\116\
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    \116\ 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.'').

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[[Page 36691]]

    The EPA hereby finds that it is both necessary and appropriate to 
regulate all new and existing EGU and industrial sources meeting the 
applicability criteria set forth in this 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 finding, the geographic scope of coverage of 
the rule means the areas of the United States encompassed within the 
borders of the states the EPA has determined to be linked at Steps 1 
and 2 of the 4-step interstate transport framework.\117\ For EGU 
applicability criteria, see section VI.B of this document; for 
industrial-source applicability criteria, see section VI.C of this 
document. To EPA's knowledge, only one existing EGU or industrial 
source is located within the CAA section 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.
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    \117\ With respect to any industrial sources located in the CAA 
section 301(d) FIP areas, the geographic scope of coverage of this 
rule does not include those states for which the EPA finds, based on 
air quality modeling, that no further linkage exists by the 2026 
analytic year at Steps 1 and 2. The states in this rule not linked 
in 2026 are Alabama, Minnesota, and Wisconsin.
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    This finding is consistent with the 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, the 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 48293 (describing 
the CSAPR methodology of allowance allocation under the ``Indian 
country new unit set-aside'' provisions); see also id. at 48217 
(explaining the 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, 
the 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 rule, the EPA is taking an approach similar to the prior 
CSAPR rulemakings with respect to regulating sources in the CAA section 
301(d) FIP areas.\118\ The EPA believes this approach is necessary and 
appropriate for several reasons. First, the purpose of this rule is to 
address the 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 rule, 
the EPA is applying--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 (as 
determined separately for linkages existing in 2023, and linkages 
persisting in 2026). (See section V of this document for a discussion 
of EPA's determination of control stringency for this rule.) 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, the 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 reduce their emissions by 
installing devices of the kind in which neighboring States have already 
invested. Id.
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    \118\ See section VI.B.9 of this document for a discussion of 
revisions that are being made 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 
rule, the importance of a uniform level of stringency that extends to 
and includes the CAA section 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, to avoid the 
regulatory costs that would be imposed under this 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 EGU or industrial sources not subject to the rule 
but located in a geography where the same types of sources 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 
the EPA's view, to avoid creating, via this rule, a structure of 
incentives that may cause generation or production--and the associated 
NOX emissions--to shift into the CAA section 301(d) FIP 
areas to escape regulation needed to eliminate interstate transport 
under the good neighbor provision.
    The EPA finds it is appropriate to directly implement the rule's 
requirements in the CAA section 301(d) FIP areas in this action rather 
than at a later date. Tribes have the opportunity to seek treatment as 
a state (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 CAA section 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

[[Page 36692]]

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 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 VI.A of this 
document, the EPA is 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 the 
application of this FIP in the CAA section 301(d) FIP areas, 
NOX emissions from any existing or new EGU or non-EGU 
sources located in, or locating in, the CAA section 301(d) FIP areas 
within the covered geography of the rule would remain unregulated for 
purposes of CAA section 110(a)(2)(D)(i)(I) for the 2015 ozone NAAQS and 
could continue or potentially increase. This would be inconsistent with 
the 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 CAA 
section 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. The EPA's Fiscal Year 2022-2026 Strategic Plan 
\119\ 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.'' As 
described in section X.F of this document, the EPA offered Tribal 
consultation to 574 Tribes in April of 2022 and received no requests 
for Tribal consultation after publication of the proposed rulemaking. 
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 rule.
---------------------------------------------------------------------------

    \119\ https://www.epa.gov/system/files/documents/2022-03/fy-2022-2026-epa-strategic-plan.pdf.
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    Therefore, to ensure timely alignment of all needed emissions 
reductions within the timetables of this 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 CAA section 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,\120\ the EPA finds it both necessary and appropriate that 
all existing and new EGU and industrial sources that are located in the 
CAA section 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 issues this finding under CAA section 
301(d)(4) of the Act and 40 CFR 49.11. Further, to avoid ``unreasonable 
delay'' in promulgating this FIP, as required under section 49.11, the 
EPA makes this finding now, to align emissions reduction obligations 
for any covered new or existing sources in the CAA section 301(d) FIP 
areas with the larger schedule of reductions under this rule. Because 
all other covered EGU and non-EGU sources within the geography of this 
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 including the CAA 
section 301(d) FIP areas in this rule now and a potentially significant 
downside to not doing so.
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    \120\ Executive Order 13985 (January 20, 2021) (86 FR 7009 
(January 25, 2021)): https://www.govinfo.gov/content/pkg/FR-2021-01-25/pdf/2021-01753.pdf.
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    The Agency recognizes that Tribal governments may still choose to 
seek TAS to develop a Tribal plan with respect to the obligations under 
this rule, and this determination does not preclude the tribes from 
taking such actions. Although the formal tribal consultation process 
associated with this action has concluded, the EPA is willing and 
available to engage with any tribe as this rule is implemented.
b. 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).\121\
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    \121\ 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 the EPA's decision, described in this 
section, on October 1, 2020.
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    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.\122\ 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

[[Page 36693]]

(collectively ``excluded Indian country lands'').
---------------------------------------------------------------------------

    \122\ Available in the docket for this rulemaking.
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    The 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 the EPA's approval of 
Oklahoma's SAFETEA request.\123\ 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).
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    \123\ The 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 the 
EPA's approval of Oklahoma's SAFETEA request.
---------------------------------------------------------------------------

    In a Federal Register document published on February 13, 2023 (88 
FR 9336), the EPA disapproved 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 the EPA's October 
1, 2020 SAFETEA approval, the EPA has authority under CAA section 
110(c) to promulgate a FIP as needed to address the disapproved aspects 
of Oklahoma's good neighbor SIP submittal.\124\ In accordance with the 
previous discussion, the EPA's FIP authority in this circumstance 
extends to all Indian country in Oklahoma, other than the excluded 
Indian country lands, as described previously.\125\ 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, the EPA's FIP authority under CAA 
section 110(c) also applies to any Indian allotments or dependent 
Indian communities located outside of an Indian reservation over which 
there has been no demonstration of tribal authority. The EPA's FIP 
authority under CAA section 110(c) similarly applies 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 rule.
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    \124\ The antecedent fact that the state had the authority and 
jurisdiction to implement requirements under the good neighbor 
provision, in the 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).
    \125\ With respect to those areas of Indian country constituting 
``excluded Indian country lands'' in the State of Oklahoma, as 
defined supra, the EPA applies 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 following finalization of 
this rule, and such change affects the exercise of FIP authority 
provided under section 110(c) of the Act,\126\ then, to the extent any 
such areas would fall more appropriately within the CAA section 301(d) 
FIP areas as described in section III.C.2.a of this document, the EPA's 
necessary or appropriate finding as set forth above with respect to all 
other CAA section 301(d) FIP areas within the geographic scope of 
coverage of the rule would apply.
---------------------------------------------------------------------------

    \126\ 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.).
---------------------------------------------------------------------------

D. Severability

    The EPA regards this action as a complete remedy, which will as 
expeditiously as practicable implement good neighbor obligations for 
the 2015 ozone NAAQS for the covered states, consistent with the 
requirements of the Act. See North Carolina v. EPA, 531 F.3d 896, 911-
12 (D.C. Cir. 2008); Wisconsin v. EPA, 938 F.3d 303, 313-20 (D.C. Cir. 
2019); Maryland v. EPA, 958 F.3d 1185, 1204 (D.C. Cir. 2020); New York 
v. EPA, 964 F.3d 1214, 1226 (D.C. Cir. 2020); New York v. EPA, 781 Fed. 
App'x 4, 7-8 (D.C. Cir. 2019) (all holding that the EPA must address 
good neighbor obligations as expeditiously as practicable and by no 
later than the next applicable attainment date). Yet should a court 
find any discrete aspect of this document to be invalid, the Agency 
believes that the remaining aspects of this rule can and should 
continue to be implemented to the extent possible. In particular, this 
action promulgates a FIP for each covered state (and, pursuant to CAA 
section 301(d), for each area of tribal jurisdiction within the 
geographic boundaries of those states). Should any jurisdiction-
specific aspect of the final rule be found invalid, the EPA views this 
rule as severable along those state and/or tribal jurisdictional lines, 
such that the rule can continue to be implemented as to any remaining 
jurisdictions. This action promulgates discrete emissions control 
requirements for the power sector and for each of seven other 
industries. Should any industry-specific aspect of the final rule be 
found invalid, the EPA views this rule as severable as between the 
different industries and different types of emissions control 
requirements. This is not intended to be an exhaustive list of the ways 
in which the rule may be severable. In the event any part of it is 
found invalid, our intention is that the remaining portions should 
continue to be implemented consistent with any judicial ruling.
    The EPA's conclusion that this rule is severable also reflects the 
important public health and environmental benefits of this rulemaking 
in eliminating significant contribution and to ensure to the greatest 
extent possible the ability of both upwind states and downwind states 
and other relevant stakeholders to be able to rely on this final rule 
in their planning. Cf. Wisconsin, 938 F.3d at 336-37 (``As a general 
rule, we do not vacate regulations when doing so would risk significant 
harm to the public health or the environment.''); North Carolina v. 
EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008) (noting the need to preserve 
public health benefits); EME Homer City v. EPA, 795 F.3d 118, 132 (D.C. 
Cir. 2015) (noting the need to avoid disruption to emissions trading 
market that had developed).

IV. 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 final rule, the EPA evaluated air quality to 
identify receptors at Step 1 for two

[[Page 36694]]

analytic years: 2023 and 2026. The EPA evaluated interstate 
contributions to these receptors from individual upwind states at Step 
2 for these two analytic years. In selecting these years, the EPA views 
2023 and 2026 to constitute years by which key emissions reductions 
from EGUs and non-EGUS can be implemented ``as expeditiously as 
practicable.'' 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). To 
demonstrate attainment by these deadlines, downwind states would be 
required to rely on design values calculated using ozone data 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 final rule can assist the downwind areas with demonstrating 
attainment or receiving extensions of attainment dates under CAA 
section 181(a)(5). (The EPA explains in detail in sections V and VI of 
this document its determinations regarding which emissions reduction 
strategies can be implemented by 2023, and which emissions reduction 
strategies require additional time beyond that ozone season, or the 
2026 ozone season.)
    It would not be logical for the EPA to analyze any earlier year 
than 2023. The EPA continues to interpret the good neighbor provision 
as forward-looking, based on Congress's use of the future-tense 
``will'' in CAA 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 the proposal, the EPA recognized that 
the 2021 Marginal area attainment date had already passed. Further, 
based on the timing of the proposal, it was not possible to finalize 
this rulemaking before the 2022 ozone season had also passed. Thus, the 
EPA has selected 2023 as the first appropriate future analytic year for 
this final 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 2026 to ensure a complete 
Step 3 analysis for future ozone transport contributions to downwind 
areas. As noted above, 2023 and 2026 coincide with the last full ozone 
seasons before future attainment dates for the 2015 ozone NAAQS. In 
addition, 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 to fully address 
significant contribution. In all cases, 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.
    Comment: A commenter claims that the EPA has not followed the 
holdings of Wisconsin v. EPA, 938 F.3d 303 (D.C. Cir. 2019), North 
Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008), and Maryland v. EPA, 
958 F. 3d 1185 (D.C. Cir. 2020) in the selection of analytic years, in 
that commenter interprets those decisions as holding that the EPA must 
``harmonize'' the exact timing of upwind emissions reductions with when 
downwind states implement their required reductions. Commenter also 
points to the EPA's proposed action on New York's Good Neighbor SIP 
submission specifically to argue that the EPA is treating upwind and 
downwind states dissimilarly. Commenter also cites CAA sections 172, 
177, and 179 to argue the EPA did not properly align upwind and 
downwind obligations. Several commenters believe the EPA should defer 
implementing good neighbor requirements until downwind receptor areas 
have first implemented their own emissions control strategies.
    Response: The EPA maintains that 2023 is an appropriate analytic 
year and comports with the relevant caselaw. Section VI.A further 
discusses the compliance schedule for emissions reductions under this 
rule. Commenter misreads the North Carolina, Wisconsin, and Maryland 
decisions as calling for good neighbor analysis and emissions controls 
to be aligned with the timing of the implementation of nonattainment 
controls by downwind states. However, the D.C. Circuit has held that 
the statutory attainment dates are the relevant downwind deadlines the 
EPA must align with in implementing the good neighbor provision. In 
Wisconsin, the court held, ``In sum, under our decision in North 
Carolina, the Good Neighbor Provision calls for elimination of upwind 
States' significant contributions on par with the relevant downwind 
attainment deadlines.'' Wisconsin, 938 F.3d. at 321 (emphasis added).
    After that decision, the EPA interpreted Wisconsin as limited to 
the attainment dates for Moderate or higher classifications under CAA 
section 181 on the basis that Marginal nonattainment areas have reduced 
planning requirements and other considerations. See, e.g., 85 FR 29882, 
29888-89 (May 19, 2020) (proposed approval of South Dakota's 2015 ozone 
NAAQS good neighbor SIP). However, on May 19, 2020, the D.C. Circuit in 
Maryland v. EPA, 958 F.3d 1185 (D.C. Cir. 2020), applying the Wisconsin 
decision, rejected that argument and held that the EPA must assess air 
quality at the next downwind attainment date, including Marginal area 
attainment dates under CAA section 181, in evaluating the basis for the 
EPA's denial of a petition under CAA section 126(b). 958 F.3d at 1203-
04. After Maryland, the EPA acknowledged that the Marginal attainment 
date is the first attainment date to consider in evaluating good 
neighbor obligations. See, e.g., 85 FR 67653, 67654 (Oct. 26, 2020) 
(final approval of South Dakota's 2015 ozone NAAQS good neighbor SIP).
    The D.C. Circuit again had occasion to revisit the Agency's 
interpretation of North Carolina, Wisconsin, and Maryland, in a 
challenge to the Revised CSAPR Update brought by the Midwest Ozone 
Group (MOG). The court declined to entertain similar arguments to those 
presented by commenters here and instead in a footnote explained that 
it had ``exhaustively summarized the regulatory framework governing 
EPA's conduct'' and that it ``[drew] on those decisions and incorporate 
them herein by reference,'' citing, among other cases, Maryland, 958 
F.3d 1185, and New York, 781 F. App'x 4. MOG v. EPA, No. 21-1146 (D.C. 
Cir. March 3, 2023), Slip Op. at 3 n.1.
    The relevance of CAA sections 172, 177, and 179 to the selection of 
the analytic year in this action is not clear. Commenter cites these 
provisions to conclude that the EPA did not appropriately consider 
downwind attainment deadlines and the timing of upwind good neighbor 
obligations. These provisions are found in subpart I, and while they 
may have continuing

[[Page 36695]]

relevance or applicability to aspects of ozone nonattainment planning 
requirements, the nonattainment dates for the 2015 ozone NAAQS flow 
from subpart 2 of title I of the CAA, and specifically CAA section 
181(a). Applying that statutory schedule to the designations for the 
2015 ozone NAAQS, the EPA has promulgated the applicable attainment 
dates in its regulations at 40 CFR 51.1303. The effective date of the 
initial designations for the 2015 ozone NAAQS was August 3, 2018 (83 FR 
25776, June 4, 2018, effective August 3, 2018).\127\ Thus, the first 
deadline for attainment planning under the 2015 ozone NAAQS was the 
Marginal attainment date of August 3, 2021, and the second deadline for 
attainment planning is the Moderate attainment date of August 3, 2024. 
If a Marginal area fails to attain by the attainment date it is 
reclassified, or ``bumped up,'' to Moderate. Indeed, the EPA has just 
completed a rulemaking action reclassifying many areas of the country 
from Marginal to Moderate nonattainment, including all of the areas 
where downwind receptors have been identified in our 2023 modeling as 
well as many other areas of the country. 87 FR 60897, 60899 (Oct. 7, 
2022).
---------------------------------------------------------------------------

    \127\ September 24, 2018, for the San Antonio area. 83 FR 35136 
(July 25, 2018).
---------------------------------------------------------------------------

    Other than under the narrow circumstances of CAA section 181(a)(5) 
(discussed further in this section), the EPA is not permitted under the 
CAA to extend the attainment dates for areas under a given 
classification. That is, no matter when or if the EPA finalizes a 
determination that an area failed to attain by its attainment date and 
reclassifies that area, the attainment date remains fixed, based on the 
number of years from the area's initial designation. See, e.g., CAA 
section 182(i) (authorizing the EPA to adjust any applicable deadlines 
for newly reclassified areas ``other than attainment dates''). As the 
D.C. Circuit has repeatedly made clear, the statutory attainment 
schedule of the downwind nonattainment areas under subpart 2 is 
rigorously enforced and is not subject to change based on policy 
considerations of the EPA or the states.

    [T]he attainment deadlines, the Supreme Court has said, are 
``the heart'' of the Act. Train v. Nat. Res. Def. Council, 421 U.S. 
60, 66, 95 S.Ct. 1470, 43 L.Ed.2d 731 (1975); see Sierra Club v. 
EPA, 294 F.3d 155, 161 (D.C. Cir. 2002) (``the attainment deadlines 
are central to the regulatory scheme'') (alteration and internal 
quotation marks omitted). The Act's central object is the 
``attain[ment] [of] air quality of specified standards [within] a 
specified period of time.'' Train, 421 U.S. at 64-65, 95 S.Ct. 1470.

Wisconsin, 938 F.3d at 316. See also Natural Resources Defense Council 
v. EPA, 777 F.3d 456, 466-68 (D.C. Cir. 2014) (holding the EPA cannot 
adjust the section 181 attainment schedule to run from any other date 
than from the date of designation); id. at 468 (``EPA identifies no 
statutory provision giving it free-form discretion to set Subpart 2 
compliance deadlines based on its own policy assessment concerning the 
number of ozone seasons within which a nonattainment area should be 
expected to achieve compliance.'') (citing and quoting Whitman v. 
American Trucking Ass'ns, 531 U.S. 457, 484, (2001) (``The principal 
distinction between Subpart 1 and Subpart 2 is that the latter 
eliminates regulatory discretion that the former allowed.''). 
Furthermore, as the court in NRDC noted, ``[T]he `attainment deadlines 
. . . leave no room for claims of technological or economic 
infeasibility.' '' 777 F.3d at 488 (quoting Sierra Club, 294 F.3d at 
161) (internal quotation marks and brackets omitted).
    With the exception of the Uinta Basin, which is not an identified 
receptor in this action, no Marginal nonattainment area met the 
conditions of CAA section 181(a)(5) to obtain a one-year extension of 
the Moderate area attainment date. 87 FR 60899. Thus, all Marginal 
areas (other than Uinta) that failed to attain have been reclassified 
to Moderate. Id. (And the New York City Metropolitan nonattainment area 
was initially classified as Moderate (see following text for further 
details).) Even if the EPA had extended the attainment date for any of 
the downwind areas, it is not clear that it would necessarily follow 
that the EPA must correspondingly extend or delay the implementation of 
good neighbor obligations. While the Wisconsin court recognized 
extensions under CAA section 181(a)(5) as a possible source of timing 
flexibility in implementing the good neighbor provision, 938 F.3d at 
320, the EPA and the states are still obligated to implement good 
neighbor reductions as expeditiously as practicable and are also 
obligated under the good neighbor provision to address ``interference 
with maintenance.'' Areas that have obtained an extension under CAA 
section 181(a)(5) or which are not designated as in nonattainment could 
still be identified as struggling to maintain the NAAQS, and the EPA is 
obligated under the good neighbor provision to eliminate upwind 
emissions interfering with the ability to maintain the NAAQS, as well. 
North Carolina, 531 F.3d at 908-11. Thus, while an extension under CAA 
section 181(a)(5) may be a source of flexibility for the EPA to 
consider in the timing of implementation of good neighbor obligations, 
as Wisconsin recognized, it is not the case that the EPA must delay or 
defer good neighbor obligations for that reason, and neither the D.C. 
Circuit nor any other court has so held.
    Commenter is therefore incorrect to the extent that they argue the 
selection of 2023 as an analytic year for upwind obligations results in 
the misalignment of downwind and upwind state obligations. To the 
contrary, both downwind and upwind state obligations are driven by the 
statutory attainment date of August 3, 2024 for Moderate areas, and the 
last year that air quality data may impact whether nonattainment areas 
are found to have attained by the attainment date is 2023. That is why, 
in the recent final rulemaking determinations that certain Marginal 
areas failed to attain by the attainment date, bumping those areas up 
to Moderate, and giving them SIP submission deadlines, reasonably 
available control measures (RACM), and reasonably RACT implementation 
deadlines, the EPA set the attainment SIP submission deadlines for the 
bumped up Moderate areas to be January 1, 2023. See 87 FR 60897, 60900 
(Oct. 7, 2022). The implementation deadline for RACM and RACT is also 
January 1, 2023. Id. This was in large part driven by the EPA's ozone 
implementation regulations, 40 CFR 51.1312(a)(3)(i), which previously 
established a RACT implementation deadline for initially classified 
Moderate as no later than January 1, 2023, and the modeling and 
attainment demonstration requirements in 40 CFR 51.1308(d), which 
require a state to provide for implementation of all control measures 
needed for attainment no later than the beginning of the attainment 
year ozone season (i.e., 2023). Given this regulatory history, the EPA 
can hardly be accused of letting states with nonattainment areas for 
the 2015 ozone NAAQS avoid or delay their mandatory CAA obligations.
    Commenter's proposal that the EPA align good neighbor obligations 
with the actual implementation of measures in downwind areas is 
untethered from the statute, as discussed above. It is also unworkable 
in practice. It would necessitate coordinating the activities of 
multiple states and EPA regional and headquarters offices to an 
impossible degree and effectively could preclude the implementation of 
good neighbor obligations altogether. Commenter does not explain how 
the EPA or upwind states should coordinate upwind emissions control 
obligations for states

[[Page 36696]]

linked to multiple downwind receptors whose states may be implementing 
their requirements on different timetables. Less drastic mechanisms 
than subjecting people living in downwind receptor areas to continuing 
high levels of air pollution caused in part by upwind-state pollution 
are available if the actual implementation of mandatory CAA 
requirements in the downwind areas is delayed: CAA section 304(a)(2) 
provides for judicial recourse where there is an alleged failure by the 
Agency to perform a nondiscretionary duty; that recourse is for the 
Agency to be placed on a court-ordered deadline to address the relevant 
obligations. See Oklahoma v. U.S. EPA, 723 F.3d 1201, 1223-24 (10th 
Cir. 2013); Montana Sulphur and Chemical Co. v. U.S. EPA, 666 F.3d 
1174, 1190-91 (9th Cir. 2012). Commenter focuses on the EPA's 
evaluation of New York's Good Neighbor SIP submission to argue the EPA 
is treating upwind and downwind states dissimilarly. The argument 
conflates New York's role as both a downwind and an upwind state. In 
evaluating the Good Neighbor SIP submission that New York submitted, 
the EPA identified as a basis for disapproval that none of the state 
emissions control programs New York cited included implementation 
timeframes to achieve the reductions, let alone ensure they were 
achieved by 2023. 87 FR 9484, 9494 (Feb. 22, 2022). The EPA conducted 
the same inquiry into other states' claims regarding their existing or 
proposed state laws or other emissions reductions claimed in their SIP 
submissions. See, e.g., 87 FR 9472-73 (evaluating claims regarding 
emissions reductions anticipated under Maryland's state law); 87 FR 
9854 (evaluating claims regarding emissions reductions anticipated 
under Illinois' state law). Consistent with its treatment of the other 
upwind states included in this action, the EPA in a separate action 
disapproved New York's good neighbor SIP submission for the 2015 ozone 
NAAQS because its arguments did not demonstrate that it had fully 
prohibited emissions significantly contributing to out of state 
nonattainment or maintenance problems.
    Commenter attempts to contrast this evaluation with what it 
believes is the EPA's permissive attitude toward delays by downwind 
states, specifically claiming that ``certain nonattainment areas have 
delayed implementation of nonattainment controls until 2025 and 
beyond.'' This apparently references New York's simple cycle and 
regenerative combustion turbines (SCCT) controls, which commenter cited 
elsewhere in its comments. New York's SCCT controls were not included 
by New York in its good neighbor SIP submission, nor was the prior 
approval of the SCCT controls reexamined by the EPA or reopened for 
consideration by the Agency in this action. Although not part of this 
rulemaking, the EPA notes that the SCCT controls were approved by the 
EPA as a SIP strengthening measure and not to satisfy any specific 
planning requirements for the 2015 ozone NAAQS under CAA section 182. 
86 FR 43956, 43958 (Aug. 11, 2021). The SCCT controls submitted to the 
EPA were already a state rule, and the only effect under the CAA of the 
EPA approving them into New York's SIP was to make them federally 
enforceable. 86 FR 43956, 43959 (Aug. 11, 2021). In other words, 
approval of the SCCT controls did not relieve New York of its 
nonattainment planning obligations for the 2015 ozone NAAQS.
    The EPA notes that the New York-Northern New Jersey-Long Island, 
NY-NJ-CT nonattainment area was initially designated as Moderate 
nonattainment. 83 FR 25776 (June 4, 2018). Pursuant to this 
designation, New York was required to submit a RACT SIP submission and 
an attainment demonstration no later than 24 months and 36 months, 
respectively, after the effective date of the Moderate designation. CAA 
section 182; 40 CFR 51.1308(a), 51.1312(a)(2). New York submitted a 
RACT SIP for the 2015 ozone standards on January 29, 2021,\128\ and the 
EPA is currently evaluating that submission. New York has not yet 
submitted its attainment demonstration, which was due August 3, 2021. 
Further, the New York-Northern New Jersey-Long Island, NY-NJ-CT 
nonattainment area remains subject to the Moderate nonattainment area 
date of August 3, 2024. If it fails to attain the 2015 ozone NAAQS by 
August 3, 2024, it will be reclassified to Serious nonattainment, 
resulting in additional requirements on the New York nonattainment 
area.
---------------------------------------------------------------------------

    \128\ https://edap.epa.gov/public/extensions/S4S_Public_Dashboard_2/S4S_Public_Dashboard_2.html.
---------------------------------------------------------------------------

    In any case, regardless of the status of New York's and the EPA's 
efforts in relation to the New York-Northern New Jersey-Long Island, 
NY-NJ-CT nonattainment area (which are outside the scope of this 
action), the EPA's evaluation of 2023 as the relevant analytic year in 
assessing New York's and other states' good neighbor obligations is 
consistent with the statutory framework and court decisions calling on 
the agency to align these obligations with the downwind areas' 
statutory attainment schedule. The EPA further responds to these 
comments in the RTC document in the docket.
    The remainder of this section includes information on (1) the air 
quality modeling platform used in support of the final rule with a 
focus on the base year and future year base case emissions inventories, 
(2) the method for projecting design values in 2023 and 2026, 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 largest predicted downwind contributions 
in 2023 and 2026 from each state. The 2016 base period and 2023 and 
2026 projected design values and contributions for all ozone monitoring 
sites are provided in the docket for this rule. The ``Air Quality 
Modeling Technical Support Document for the Federal Good Neighbor Plan 
for the 2015 Ozone National Ambient Air Quality Standards Final 
Rulemaking'' (Mar. 2023), hereinafter referred to as the Air Quality 
Modeling Final Rule TSD, in the docket for this final 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 3 of the 2016-based modeling platform (i.e., 
2016v3) for the air quality modeling for this final rule. This modeling 
platform includes 2016 base year emissions from anthropogenic and 
natural sources and anthropogenic emissions projections for 2023 and 
2026. The emissions data contained in this platform represent an update 
to the 2016 version 2 inventories used for the proposal modeling.
    The air quality modeling for this final rule 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 which is the same model that 
EPA used for the proposed rule air quality modeling.\129\ Additional 
information on the 2016-based air quality modeling platform can be 
found in the Air Quality Modeling Final Rule TSD.
---------------------------------------------------------------------------

    \129\ Ramboll Environment and Health, January 2021, https://www.camx.com.
---------------------------------------------------------------------------

    Comment: Commenters noted that the 2016 base year summer maximum 
daily average 8-hour (MDA8) ozone predictions from the proposal 
modeling were biased low compared to the corresponding measured 
concentrations in certain locations. In this regard, commenters said 
that model

[[Page 36697]]

performance statistics for a number of monitoring sites, particularly 
those in portions of the West and in the area around Lake Michigan, 
were outside the range of published performance criteria for normalized 
mean bias (NMB) and normalized mean error (NME) of less than 15 percent and less than 25 percent, respectively (Emory, et al., 
2017).\130\ The commenters said EPA must investigate the factors 
contributing to low bias and make necessary corrections to improve 
model performance in the final rule modeling. Some commenters said that 
EPA should include NOX emissions from lightning strikes and 
assess the treatment of other background sources of ozone to improve 
model performance for the final rule. Additional information on the 
comments on model performance can be found in the RTC document for this 
final rule.
---------------------------------------------------------------------------

    \130\ Christopher Emery, Zhen Liu, Armistead G. Russell, M. 
Talat Odman, Greg Yarwood & Naresh Kumar (2017) Recommendations on 
statistics and benchmarks to assess photochemical model performance, 
Journal of the Air & Waste Management Association, 67:5, 582-598, 
DOI: 10.1080/10962247.1265027.
---------------------------------------------------------------------------

    Response: In response to these comments EPA examined the temporal 
and spatial characteristics of model under prediction to investigate 
the possible causes of under prediction of MDA8 ozone concentrations in 
different regions of the U.S. in the proposal modeling. EPA's analysis 
indicates that the under prediction was most extensive during May and 
June with less bias during July and August in most regions of the U.S. 
For example, in the Upper Midwest region model under prediction was 
larger in May and June compared to July through September. 
Specifically, in the proposal modeling, the normalized mean bias for 
days with measured concentrations >=60 ppb improved from a 21.4 percent 
under prediction for May and June to a 12.6 percent under prediction in 
the period July through September. As described in the Air Quality 
Modeling Final Rule TSD, the seasonal pattern in bias in the Upper 
Midwest region improves somewhat gradually with time from the middle of 
May to the latter part of June. In view of the seasonal pattern in bias 
in the Upper Midwest and in other regions of the U.S., EPA focused its 
investigation of model performance on model inputs that, by their 
nature, have the largest temporal variation within the ozone season. 
These inputs include emissions from biogenic sources and lightning 
NOX, and contributions from transport of international 
anthropogenic emissions and natural sources into the U.S. Both biogenic 
and lightning NOX emissions in the U.S. dramatically 
increase from spring to summer.131 132 In contrast, ozone 
transported into the U.S. from international anthropogenic and natural 
sources peaks during the period March through June, with lower 
contributions during July through September.133 134 To 
investigate the impacts of these sources, EPA conducted sensitivity 
model runs which focused on the effects on model performance of adding 
NOX emissions from lightning strikes, updating biogenic 
emissions, and using an alternative approach for quantifying transport 
of ozone and precursor pollutants into the U.S. from international 
anthropogenic and natural sources. The development of lightning 
NOX emissions and the updates to biogenic emissions, are 
described in section IV.C of this document. In the proposal modeling 
the amount of transport from international anthropogenic and natural 
sources was based on a simulation of the hemispheric version of the 
Community Multi-scale Air Quality Model (H-CMAQ) for 2016.\135\ The 
outputs from this hemispheric modeling were then used to provide 
boundary conditions for national scale air quality modeling at 
proposal.\136\ Overall, H-CMAQ tends to under-predict daytime ozone 
concentrations at rural and remote monitoring sites across the U.S. 
during the spring of 2016 whereas the predictions from the GEOS-Chem 
global model \137\ were generally less biased.\138\ During the summer 
of 2016 both models showed varying degrees of over prediction with 
GEOS-Chem showing somewhat greater over-prediction, compared to H-CMAQ. 
In view of those results, EPA examined the impacts of using GEOS-Chem 
as an alternative to H-CMAQ for providing boundary conditions for the 
final rule modeling.
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    \131\ Guenther, A.B., 1997. Seasonal and spatial variations in 
natural volatile organic compound emissions. Ecol. Appl. 7, 34-45. 
https://doi.org/10.1890/1051-0761(1997)007[0034:SASVIN]2.0.CO;2. 
Guenther, A., Hewitt, C.N., Erickson, D., Fall, R.
    \132\ Kang D, Mathur R, Pouliot GA, Gilliam RC, Wong DC. 
Significant ground-level ozone attributed to lightning-induced 
nitrogen oxides during summertime over the Mountain West States. NPJ 
Clim Atmos Sci. 2020 Jan 30;3:6. doi: 10.1038/s41612-020-0108-2. 
PMID: 32181370; PMCID: PMC7075249.
    \133\ Jaffe DA, Cooper OR, Fiore AM, Henderson BH, Tonnesen GS, 
Russell AG, Henze DK, Langford AO, Lin M, Moore T. Scientific 
assessment of background ozone over the U.S.: Implications for air 
quality management. Elementa (Wash DC). 2018;6(1):56. doi: 10.1525/
elementa.309. PMID: 30364819; PMCID: PMC6198683.
    \134\ Henderson, B.H., P. Dolwick, C. Jang, A., Eyth, J. 
Vukovich, R. Mathur, C. Hogrefe, N. Possiel, G. Pouliot, B. Timin, 
K.W. Appel, 2019. Global Sources of North American Ozone. Presented 
at the 18th Annual Conference of the UNC Institute for the 
Environment Community Modeling and Analysis System (CMAS) Center, 
October 21-23, 2019.
    \135\ Mathur, R., Gilliam, R., Bullock, O.R., Roselle, S., 
Pleim, J., Wong, D., Binkowski, F., and 1 Streets, D.: Extending the 
applicability of the community multiscale air quality model to 2 
hemispheric scales: motivation, challenges, and progress. In: Steyn 
DG, Trini S (eds) Air 3 pollution modeling and its applications, 
XXI. Springer, Dordrecht, pp 175-179, 2012.
    \136\ Boundary conditions are the concentrations of pollutants 
along the north, east, south, and west boundaries of the air quality 
modeling domain. Boundary conditions vary in space and time and are 
typically obtained from predictions of global or hemispheric models. 
Information on how boundary conditions were developed for the final 
rule modeling can be found in the Air Quality Modeling Final Rule 
TSD.
    \137\ I. Bey, D.J. Jacob, R.M. Yantosca, J.A. Logan, B.D. Field, 
A.M. Fiore, Q. Li, H.Y. Liu, L.J. Mickley, M.G. Schultz. Global 
modeling of tropospheric chemistry with assimilated meteorology: 
model description and evaluation. J. Geophys. Res. Atmos., 106 
(2001), pp. 23073-23095, 10.1029/2001jd000807.
    \138\ Henderson, B.H., P. Dolwick, C. Jang, A., Eyth, J. 
Vukovich, R. Mathur, C. Hogrefe, G., N. Possiel, B. Timin, K.W. 
Appel, 2022. Meteorological and Emission Sensitivity of Hemispheric 
Ozone and PM2.5. Presented at the 21st Annual Conference 
of the UNC Institute for the Environment Community Modeling and 
Analysis System (CMAS) Center, October 17-19, 2022.
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    For the lightning NOX, biogenics, and GEOS-Chem 
sensitivity runs, EPA reran the proposal modeling using each of these 
inputs, individually. Results from these sensitivity runs indicate that 
each of the three updates provides an improvement in model performance. 
However, by far the greatest improvement in model performance is 
attributable to the use of GEOS-Chem. In view of these results EPA has 
included lightning NOX emissions, updated biogenic 
emissions, and international transport from GEOS-Chem in the final rule 
air quality modeling. Details on the results of the individual 
sensitivity runs can be found in the Air Quality Modeling Final Rule 
TSD. For the air quality modeling supporting this final action, model 
performance based on days in 2016 with measured MDA8 ozone >=60 ppb is 
considerably improved (i.e., less bias and error) compared to the 
proposal modeling in nearly all regions of the U.S. For example, in the 
Upper Midwest, which includes monitoring sites along Lake Michigan, the 
normalized mean bias improved from a 19 percent under prediction to a 
6.9 percent under prediction and in the Southwest region, which 
includes monitoring sites in Denver and Salt Lake City, normalized mean 
bias improved from a 13.6 percent under prediction to a 4.8 percent 
under prediction.\139\ In all regions, the

[[Page 36698]]

normalized mean bias and normalized mean error statistics for high 
ozone days based on the final rule modeling are within the range of 
performance criteria benchmarks (i.e., < 15 percent for 
normalized mean bias and <25 percent for normalized mean error).\140\ 
Additional information on model performance is provided in the Air 
Quality Modeling Final Rule TSD. In summary, EPA included emissions of 
lightning NOX, as requested by commenters, and investigated 
and addressed concerns about model performance for the final rule 
modeling.
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    \139\ A comparison of model performance from the proposal 
modeling to the final modeling for individual monitoring sites can 
be found in the docket for this final rule.
    \140\ Christopher Emery, Zhen Liu, Armistead G. Russell, M. 
Talat Odman, Greg Yarwood & Naresh Kumar (2017) Recommendations on 
statistics and benchmarks to assess photochemical model performance, 
Journal of the Air & Waste Management Association, 67:5, 582-598, 
DOI: 10.1080/10962247.1265027.
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C. Emissions Inventories

    The EPA developed emissions inventories to support air quality 
modeling for this final rule, including emissions estimates for EGUs, 
non-EGU point sources (i.e., stationary 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. The 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.
    Prior to air quality modeling, the emissions inventories were 
processed into a format that is appropriate for the air quality model 
to use. 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 4.9 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 document titled, ``Technical 
Support Document (TSD): Preparation of Emissions Inventories for the 
2016v3 North American Emissions Modeling Platform'' (Jan. 2023), 
hereafter known as the 2016v3 Emissions Modeling TSD. This TSD is 
available in the docket for this rule.\141\
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    \141\ See 2016v3 Emissions Modeling TSD, also available at 
https://www.epa.gov/air-emissions-modeling/2016v3-platform.
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1. Foundation Emissions Inventory Data Sets
    The 2016v3 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 through 2022, in 
addition to data retained 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. The 
2016v2 platform used to support the proposed action included updated 
data from the 2017 NEI along with updates to models and methods as 
compared to 2016v1. The 2016v3 platform includes updates to the 2016v2 
platform implemented in response to comments along with other updates 
to the 2016v2 platform such as corrections and the incorporation of 
updated data sources that became available prior to the 2016v3 
inventories being developed. Several commenters noted that the 2016v2 
platform did not include NOX emissions that resulted from 
lightning strikes. To address this, lightning NOX emissions 
were computed and included in the 2016v3 platform.
    For this final rule, the EPA developed emissions inventories for 
the base year of 2016 and the projected years of 2023 and 2026. The 
2023 and 2026 inventories 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.\142\ The 2016 emissions inventories for 
the U.S. primarily include data derived from the 2017 National 
Emissions Inventory (2017 NEI) \143\ and data specific to the year of 
2016. The following sections provide an overview of the construct of 
the 2016v3 emissions and projections. The fire emissions were unchanged 
between the 2016v2 and 2016v3 emissions platforms. For the 2016v3 
platform, the biogenic emissions were updated to use the latest 
available versions of the Biogenic Emissions Inventory System and 
associated land use data to help address comments related to a 
degradation in model performance in the 2016v2 platform as compared to 
the 2016v1 platform. Details on the construction of the inventories are 
available in the 2016v3 Emissions Modeling TSD. Details on how the EPA 
responded to comments related to emissions inventories are available in 
the RTC document for this rule.
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    \142\ 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.
    \143\ https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-technical-support-document-tsd.
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2. Development of Emissions Inventories for EGUs
a. EGU Emissions Inventories Supporting This Final Rule
    Development of emissions inventories for 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 by the state, local, and tribal agencies. 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. Emissions 
data for EGUs that did not have data submitted to the NEI specific to 
the year 2016 were filled in with data from the 2017 NEI. For more 
information on the details of how the 2016 EGU emissions were developed 
and prepared for air quality modeling, see the 2016v3 Emissions 
Modeling TSD.
    The EPA projected 2023 and 2026 baseline EGU emissions using the 
version 6--Updated 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-

[[Page 36699]]

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.\144\ 
The EPA relied on the same model platform at final as it did at 
proposal, but made substantial updates to reflect public comments on 
near-term fossil fuel market price volatility and updated fleet 
information reflecting Summer 2022 U.S. Energy Information Agency (EIA) 
860 data, unit-level comments, and additional updates to the National 
Electric Energy Data System (NEEDS) inventory.
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    \144\ Detailed information and documentation of EPA's Base Case, 
including all the 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--Updated Summer 2021 Reference Case incorporated 
recent updates through the Summer of 2022 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 
EIA's Annual Energy Outlook (AEO) 2020. Natural gas and coal price 
projections reflect data developed in Fall 2020 but updated in summer 
of 2022 to capture near-term price volatility and current market 
conditions. The inventory of EGUs provided as an input to the model was 
the NEEDS fall 2022 version and is available on EPA's website.\145\ 
This version of NEEDS reflects announced retirements and under-
construction new builds known as of early summer 2022. 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, NSR enforcement settlements, the final ELG Rule, 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 best available retrofit technology (BART) 
requirements. Documentation of IPM version 6 and NEEDS, along with 
updates, is in Docket ID No. EPA-HQ-OAR-2021-0668 and available online 
at https://www.epa.gov/airmarkets/power-sector-modeling. 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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    \145\ 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 adopted a similar 
approach to the CSAPR Update and the Revised CSAPR Update where it 
utilized historical data and an engineering analytics approach 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 starting with unit-level reported data 
and only making adjustments to reflect known baseline changes such as 
planned retirements and new builds (for the base case scenarios) and 
also identified mitigation strategies for determining state emissions 
budgets. In both the CSAPR Update and in this rule at Step 3, the EPA 
complemented that projected IPM EGU outlook with an 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 Final 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 document.
    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 regional changes 
that are anticipated in response to market forces and fleet trends, the 
Engineering Analysis deliberately creates future estimates of the power 
sector where state estimates are limited to known changes. 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 the current analytic 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 
the 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 determine that 
regardless of which EGU inventory is used, the 2023 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 
one limited to current data and known changes (Engineering Analysis), 
the states that are linked to receptors at Steps 1 and 2 would be the 
same. This finding is consistent with the observation that EGUs are now 
less than

[[Page 36700]]

10 percent 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. 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 Ozone Transport Policy Analysis Final Rule TSD contains 
data on 2023 and 2026 AQ impacts of each dataset.
    Comment: Some commenters express concern that using IPM for Step 1 
and Step 2 captures generation shifting across state lines, which 
exceeds the EPA's authority. Moreover, the commenters suggest that the 
resulting proposed baseline EGU inventory may understate emissions 
levels as it projects economic retirements that are not yet announced 
or firm. Other commenters more generally allege that the EPA is using 
different modeling tools at different steps in its analysis, and this 
introduces confusion or uncertainty into the basis for the EPA's 
regulatory conclusions.
    Response: The EPA believes the first aspect of this comment, in 
regards to its focus on generation shifting, is misguided in several 
ways. For Step 1 and Step 2, the EPA models no incremental generation 
shifting attributable to the implementation of an emissions control 
policy at Step 3. Rather, any generation patterns are merely a 
reflection of the model's projection of how regional load requirements 
will be met with the generation sources serving that region in the 
baseline. The EPA is not modeling any additional generation shifting, 
but merely capturing the expected generation dispatch under anticipated 
baseline market conditions. Electricity generated in one state 
regularly is transmitted across state boundaries and is used to serve 
load in other states; IPM is not incentivizing or requiring any 
additional generation transfer across state lines in this scenario but 
is merely projecting the pattern of this behavior in the future. 
Moreover, as noted previously, the EPA affirms its geographic findings 
at Step 2 (states contributing over 1 percent of the NAAQS to a 
downwind receptor) using historical data (engineering analysis) in a 
sensitivity analysis. These historical data reflect the actual 
generation patterns observed to meet regional load. Therefore, any 
suggestion by the commenter that the EPA's projected view of baseline 
grid dispatch is unreasonable, is mooted by the fact that the use of 
historical reported generation patterns produces the same result. 
Additionally, at the time of the proposal's analysis, the 2023 ozone 
season was still nearly two years away. Therefore, it was appropriate 
for EPA's modeling to project economic retirements as those 
retirements--which are regularly occurring--are often not firm or 
announced two years in advance. However, for this final rule, the 2023 
analytic year was close enough to the period in which EPA was 
conducting its analysis that such retirements would likely be 
announced. Therefore, the EPA was able to incorporate those announced 
and firm retirements to occur in the 2023 year. Further, in recognition 
of this very near timeframe, we deactivated IPM's ability to project 
additional economic retirements for the 2023 year (reflecting the 
notion that any retirements occurring by 2023 would be known at this 
point). This adjustment further accommodates the commenters' concern 
that the baseline overstates generation shifting (driven by 
retirements) in the near term, and consequently understates emissions 
levels. Finally, with respect to comments that the EPA is using 
different modeling tools at different steps in the framework, we 
previously explained why these techniques are appropriate for the 
purposes at each step of the analysis, and they are not incompatible 
nor do they produce results so different as to call into question their 
reliability or the bases for our regulatory determinations (EPA notes 
that the nationwide projected ozone season total NOX 
emissions vary by less than 1 percent in the 2023 analytic year). 
Nonetheless, we also observe that the effect of using engineering 
analytics to inform analysis at Steps 1 and 2 would tend to produce 
higher assumed emissions from EGUs in the baseline than IPM would 
project in 2026 and beyond and therefore only strengthen and further 
affirm the Step 1 and Step 2 geographic findings. EPA's use of 
different tools to project EGU scenarios is not inconsistent, but 
rather it is carefully explained as a deliberate measure taken to 
preserve--not introduce--consistency across each of the Steps in the 4-
step framework. By using IPM at Step 1 and 2, EPA is selecting the more 
conservative approach for identifying the degree of nonattainment and 
geography of states contributing above 1 percent. By using Engineering 
Analytics at Step 3, EPA is selecting the more conservative value to 
codify into state-level budgets.
b. Impact of the Inflation Reduction Act on EGU Emissions
    The EGU modeling used to construct the EGU emissions inventories 
used to inform the modeling projections for 2023 and 2026 was conducted 
prior to the passage of the Inflation Reduction Act (IRA), Public Law 
117-169. The EPA did not have time to incorporate updated EGU 
projections reflecting the passage of the IRA into the primary air 
quality modeling for this final rule. However, the EPA was able to 
perform a sensitivity analysis reflecting the IRA in its EGU 
NOX emissions inventories. The results from this scenario 
were run through AQAT and demonstrated that the status of states 
identified as linked at the 1 percent of NAAQS contribution threshold 
(based on the modeling and air quality analysis described in this 
section) would not change regardless of which inventory (with or 
without IRA) is used. This sensitivity analysis is presented in the 
Regulatory Impact Analysis accompanying this rule, and that discussion 
provides additional detail on the emissions consequences of including 
the IRA in a baseline EGU inventory. The air quality impact of 
including the IRA in EPA's emissions inventories and in its Step 3 
scenarios is discussed in Appendix K of the Ozone Transport Policy 
Analysis Final Rule TSD.
    The results of this analysis are not surprising and accord with 
what is generally understood to be the overall effect of the IRA over 
the short to long term. While the IRA is anticipated to have a 
potentially dramatic effect on reducing both GHG and conventional 
pollutant emissions from the power sector, it is likely to have a more 
substantial impact later in the forecast period (i.e., beyond the 
attainment deadlines by which the emissions reductions under this final 
rule must occur). This timing reflects a realistic assessment of 
utilities', regulators', and transmission authorities' planning 
requirements associated with the addition of substantial new renewable 
and storage capacity to the grid, as well as the time needed to 
integrate that capacity and retire existing capacity. Additionally, the 
IRA incentives span a longer time period (for example, certain tax 
incentives for clean energy sources are available until the later of 
2032 or the year in which power sector emissions are 75 percent below 
2022 levels) and therefore there is no IRA-related deadline to build 
cleaner generation by 2026. Recent analysis by the Congressional Budget 
Office supports the finding that the majority of power sector EGU 
emissions reductions expected from the IRA occur well after the 2023 
and 2026 analytic years relevant to the attainment dates and this

[[Page 36701]]

rulemaking.\146\ While the report focuses on CO2 rather than 
NOX, the drivers of the emissions reductions (primarily 
increased zero-emitting generation) would generally have a downward 
impact on both pollutants.
---------------------------------------------------------------------------

    \146\ ``Emissions of Carbon Dioxide In the Electric Power 
Sector,'' Congressional Budget Office. December 2022. Available at 
https://www.cbo.gov/publication/58860.
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    We note that important uncertainties remain at this time in the 
implementation of the IRA that further counsel against over-assuming 
short-term emissions reductions for purposes of this rule. The 
legislation provides economic incentives for shifting to cleaner forms 
of power generation but does not mandate emissions reductions through 
an enforceable regulatory program. The strength of those incentives 
will vary to some extent depending on other key market factors (such as 
the cost of natural gas or renewable energy technologies). Further, 
some incentives, such as tax credits for carbon capture and storage, 
could lead EGUs to remain in operation longer, which could in turn 
result in greater NOX emissions, if those emissions are not 
also well controlled.
    Nonetheless, while we find that the passage of the IRA does not 
affect the geography of the rule in terms of which states we identify 
as linked, the Agency is confident that the incentives toward clean 
technology provided in the IRA will, in the longer run beyond the 2015 
ozone NAAQS attainment deadlines, facilitate ongoing EGU compliance 
with the emissions reduction requirements of this rule and will reduce 
costs borne by EGUs and their customers as the U.S. power sector 
transitions. As discussed in greater detail in section VI.B of this 
document, we have made several adjustments in the final rule to provide 
greater flexibility to EGU owners and operators to integrate this 
rule's requirements with and facilitate the accelerating transition to 
an overall cleaner electricity-generating sector, which the IRA 
represents. Despite the uncertainties inherent in the implementation of 
the IRA at this time, the EPA also has performed a sensitivity analysis 
on the final rule to confirm that our finding of no overcontrol is 
robust to a future with the IRA in effect.
3. Development of Emissions Inventories for Stationary Industrial Point 
Sources
    Non-EGU point source emissions are mostly consistent with those in 
the proposal modeling except where they were updated in response to 
comments. Several commenters mentioned that point source emissions 
carried forward from 2014 NEI were not the best estimates of 2017 
emissions. Thus, emissions sources in 2016v2 that had been projected 
from the 2014 NEI in the proposal were replaced with emissions based on 
the 2017 NEI. Point source emissions submitted to the 2016 NEI or to 
the 2016v1 platform development process specifically for the year 2016 
were retained in 2016v3. Other 2016 non-EGU updates in 2016v3 include a 
few sources being moved to the EGU inventory, the addition of some 
control efficiency information for the year 2016, the replacement of 
most emissions projected from 2014 NEI with data from 2017 NEI, and the 
inclusion of point source data for solvent processes that had not been 
included in the 2016v2 non-EGU inventory.
    The 2023 and 2026 non-EGU point source emissions were grown from 
2016 to those years using factors based on the AEO 2022 and reflect 
emissions reductions due to known national and local rules, control 
programs, plant closures, consent decrees, and settlements that could 
be computed as reductions to specific units by July 2022.
    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. The EPA developed and 
applied factors to adjust the 2017 airport emissions to 2016, 2023 and 
2026 based on activity growth projected by the Federal Aviation 
Administration Terminal Area Forecast 2021 \147\ data, the latest 
available version at the time the factors were developed. By basing the 
factors on the latest available Terminal Area Forecast that was 
released following the most significant pandemic impacts on the 
aviation sector, the reduction and rebound impacts of the pandemic on 
aircraft and ground support equipment were reflected in the 2023 and 
2026 airport emissions.
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    \147\ 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 2023, and 2026 with the fleet mix 
assumed to be constant throughout the period.
    The EPA made multiple updates to point source oil and gas emissions 
in response to comments. For the final rule, the point source oil and 
gas emissions for 2016 were based on the 2016v2 point inventory except 
that most 2014 NEI-based emissions were replaced with 2017 NEI 
emissions. Additionally, in response to comments, state-provided 
emissions equivalent to those in the 2016v1 platform were used for 
Colorado, and some New Mexico emissions were replaced with data 
backcast from 2020 to 2016. To develop inventories for 2023 and 2026 
for the final rule, the year 2016 oil and gas point source inventories 
were first projected to 2021 values based on actual historical 
production data, then those 2021 emissions were projected to 2023 and 
2026 using regional projection factors based on AEO 2022 projections. 
This was an update from the proposal approach that used actual data 
only through the year 2019, because 2021 data were not yet available. 
NOX and VOC reductions resulting from co-benefits of NSPS 
for Stationary Reciprocating Internal Combustion Engines (RICE) are 
reflected, along with Natural Gas Turbine and Process Heater NSPS 
NOX controls and Oil and Gas NSPS VOC controls. In some 
cases, year 2019 point source inventory data were used instead of the 
projected future year emissions except for the Western Regional Air 
Partnership (WRAP) states of Colorado, New Mexico, Montana, Wyoming, 
Utah, North Dakota, and South Dakota. The WRAP future year inventory 
\148\ was used in these WRAP states in all future years except in New 
Mexico where the WRAP base year emissions were projected using the EIA 
historical and AEO forecasted production data. Estimated impacts from 
the New Mexico Administrative code 20.2.50 \149\ were also included.
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    \148\ http://www.wrapair2.org/pdf/WRAP_OGWG_2028_OTB_RevFinalReport_05March2020.pdf.
    \149\ https://www.srca.nm.gov/parts/title20/20.002.0050.html.
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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

[[Page 36702]]

developed the onroad mobile source emissions for states other than 
California using the 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 the 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 
were developed based on emissions factors output from MOVES3 runs 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 those used 
to develop the 2017 NEI. The onroad emissions were computed within 
SMOKE by multiplying emissions factors developed using MOVES with the 
appropriate activity data. Prior to computing the final rule emissions, 
updates to some onroad inputs were made in response to comments and to 
implement corrections. Onroad mobile source emissions for California 
were consistent with the updated emissions data provided by the state 
for the final rule.
    The 2023 and 2026 onroad emissions reflect projected changes to 
fuel properties and usage, along with the impact of the rules included 
in MOVES3 for each of those years. MOVES emissions factors for the 
years 2023 and 2026 were used. A comprehensive list of control programs 
included for onroad mobile sources is available in the 2016v3 Emissions 
Modeling TSD. Year 2023 and 2026 activity data for onroad mobile 
sources were provided by some state and local agencies, and otherwise 
were projected to 2023 and 2026 by first projecting the 2016 activity 
to year 2019 based on county level vehicle miles traveled (VMT) from 
the Federal Highway Administration. Because VMT for onroad mobile 
sources were substantially impacted by the pandemic and took about two 
years to rebound to pre-pandemic levels, in the 2016v3 platform no 
growth in VMT was implemented from 2019 to. The estimated 2021 VMT were 
then grown from 2021 to 2023 and 2026 using AEO 2022-based factors. 
Recent updates to inspection and maintenance programs in North Carolina 
and Tennessee were reflected in the MOVES inputs for the final rule 
modeling. The 2023 and 2026 onroad mobile emissions were computed 
within SMOKE by multiplying the respective emissions factors developed 
using MOVES with the year-specific activity data. Prior to computing 
the final rule emissions for 2023, the EPA made updates to some onroad 
inputs in response to comments and to implement corrections.
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 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 category 3 (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 and 2026 were incorporated into the 
projected emissions for CMV sources. The CMV emissions were split into 
emissions inventories from the larger 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 projected 
emissions for the years of 2023 and 2026 instead of 2023 and 2028. In 
addition, in response to comments, the EPA implemented an improved 
process for spatial allocating CMV emissions along state and county 
boundaries.
6. Development of Emissions Inventories for Other Nonroad Mobile 
Sources
    The EPA developed nonroad mobile source emissions inventories 
(other than CMV, locomotive, and aircraft emissions) for 2016, 2023, 
and 2026 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 nonroad emissions for the final rule were 
unchanged from those at the proposal. 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 2016v3 
Emissions Modeling TSD.
    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 locomotive emissions were developed through the 
2016v1 collaborative process and the year 2016 emissions are mostly 
consistent with those in the 2017 NEI. More information on the 
development of the Class I, Class II and III, and commuter rail line 
haul locomotive emissions is available in the 2016v3 Emissions Modeling 
TSD. The projected locomotive emissions for 2023 and 2026 were 
developed by applying factors to the 2016 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. The 
emission factors used for NOX, PM10 and VOC for line haul 
locomotives in the analytic years were derived from trend lines based 
on historic line-haul emission factors from the period of 2007 through 
2017 and extrapolated to 2023 and 2026.
7. Development of Emissions Inventories for Nonpoint Sources
    For stationary nonpoint sources, some emissions in the 2016 base 
case emissions inventory come directly from the 2017 NEI, others were 
adjusted from the 2017 NEI to represent 2016 levels, and the remaining 
emissions including those from oil and gas, fertilizer, and solvents 
were computed specifically to represent 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 derived from 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 recent method 
to compute solvent VOC emissions was used.\150\
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    \150\ https://doi.org/10.5194/acp-21-5079-2021.
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    Where comments were provided about projected control measures or

[[Page 36703]]

changes in nonpoint source emissions, those inputs were first reviewed 
by the EPA. Those found to be based on reasonable data for affected 
emissions sources were incorporated into the projected inventories for 
2023 and 2026 to the extent possible. Where possible, projection 
factors based on the AEO used data from AEO 2022, the most recent AEO 
at the time available at the time the inventories were developed. 
Federal regulations that impact the nonpoint sources were reflected in 
the inventories. Adjustments for state fuel sulfur content rules for 
fuel oil in the Northeast were included along with solvent controls 
applicable within the ozone transport region. Details are available in 
the 2016v3 Emissions Modeling TSD.
    Nonpoint oil and gas emissions inventories for many states were 
developed based on outputs from the 2017 NEI version of the EPA Oil and 
Gas Tool using activity data for year 2016. Production-related 
emissions data from the 2017 NEI were used for Oklahoma, 2016v1 
emissions were used for Colorado and for Texas production-related 
sources to response to comments. Data for production-related nonpoint 
oil and gas emissions in the states of Colorado, Montana, New Mexico, 
North Dakota, South Dakota, Utah, and Wyoming were obtained from the 
WRAP baseline inventory.\151\ A California Air Resources Board-provided 
inventory was used for 2016 oil and gas emissions in California. 
Nonpoint oil and gas inventories for 2023 and 2026 were developed by 
first projecting the 2016 oil and gas inventories to 2021 values based 
on actual production data. Next, those 2021 emissions were projected to 
2023 and 2026 using regional projection factors by product type based 
on AEO 2022 projections. A 2017-2019 average inventory was used for oil 
and natural gas exploration emissions in 2023 and 2026 except for 
California and in the WRAP states in which data from the WRAP future 
year inventory \152\ were used. NOX and VOC reductions that 
are co-benefits to the NSPS for RICE are reflected, along with Natural 
Gas Turbines and Process Heaters NSPS NOX controls and NSPS 
Oil and Gas VOC controls. The WRAP future year inventory was used for 
oil and natural gas production sources in 2023 and 2026 except in New 
Mexico where the WRAP Base year emissions were projected using the EIA 
historical and AEO forecasted production data. Estimated impacts from 
the New Mexico Administrative Code 20.2.50 were included.
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    \151\ http://www.wrapair2.org/pdf/WRAP_OGWG_Report_Baseline_17Sep2019.pdf.
    \152\ http://www.wrapair2.org/pdf/WRAP_OGWG_2028_OTB_RevFinalReport_05March2020.pdf.
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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 and 2026 analytic years. Where the EPA's 
analysis shows that an area or site does not fall under the definition 
of a nonattainment or maintenance receptor in these analytic years, 
that site is excluded from further analysis under this rule.
    In the proposed rule, the EPA applied the same approach used in the 
CSAPR Update and the Revised CSAPR Update to identify nonattainment and 
maintenance receptors for the 2008 ozone NAAQS.\153\ See 86 FR 23078-
79. The 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.\154\ 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.
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    \153\ See 86 FR 23078-79.
    \154\ 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)).
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    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.\155\
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    \155\ 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).
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    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 monitoring 
sites that also measure nonattainment for the most recent period of 
available ambient data. The EPA separately identified maintenance 
receptors as those monitoring sites that would have difficulty 
maintaining the relevant NAAQS in a scenario that accounts for 
historical variability in air quality at that site. The variability in 
air quality was determined by evaluating the ``maximum'' future design 
value at each monitoring site 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 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.\156\ 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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    \156\ 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.
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    Therefore, applying this methodology in this rule, the EPA assessed 
the magnitude of the projected maximum design values for 2023 and 2026 
at each monitoring site 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.\157\ That is,

[[Page 36704]]

monitoring sites with a maximum design value that exceeds the NAAQS are 
projected to have maintenance problems in the future analytic 
years.\158\
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    \157\ See 795 F.3d at 136.
    \158\ 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-
2021-0668 or at https://www.epa.gov/airmarkets/memo-and-supplemental-information-regarding-interstate-transport-sips-2015-ozone-naaqs. EPA is not applying the suggested analytical approaches 
in that memorandum in this rule, nor would those approaches be 
appropriate in light of currently available data. 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.
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    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 
previously, 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.\159\
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    \159\ See https://www.epa.gov/air-trends/air-quality-design-values for design value reports. At the time of this action, the 
most recent reports available are for the calendar year 2021.
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    Comment: The EPA received comments claiming that the projected 
design values for 2023 were biased low compared to recent measured 
data. Commenters noted that a number of monitoring sites that are 
projected to be below the NAAQS in 2023 based on the EPA's modeling for 
the proposed action are currently measuring nonattainment based on data 
from 2020 and 2021. One commenter requested that the EPA determine 
whether its past modeling tends to overestimate or underestimated 
actual observed design values. If EPA finds that the agency's model 
tends to underestimate future year design values, the commenter 
requests that EPA re-run its ozone modeling, incorporating parameters 
that account for this tendency.
    Response: In response to comments, the EPA compared the projected 
2023 design values based on the proposal modeling to recent trends in 
measured data. As a result of this analysis, the EPA agrees that 
current data indicate that there are monitoring sites at risk of 
continued nonattainment in 2023 even though the model projected average 
and maximum design values at these sites are below the NAAQS (i.e., 
sites that are not modeling-based receptors). It would not be 
reasonable to ignore recent measured ozone levels in many areas that 
are clearly not fully consistent with certain concentrations in the 
Step 1 analysis for 2023. Therefore, the EPA has also developed an 
additional maintenance-only receptor category, which includes what we 
refer to as ``violating monitor'' receptors, based on current ozone 
concentrations measured by regulatory ambient air quality monitoring 
sites.
    Specifically, the EPA has identified monitoring sites with measured 
2021 and preliminary 2022 design values and 4th high maximum daily 8-
hour average (MDA8) ozone in both 2021 and 2022 (preliminary data) that 
exceed the NAAQS, although projected to be in attainment in 2023, as 
having the greatest risk of continuing to have a problem attaining the 
standard in 2023. These criteria sufficiently consider measured air 
quality data so as to avoid including monitoring sites that have 
measured nonattainment data in recent years but could reasonably be 
anticipated to not have a nonattainment or maintenance problem in 2023, 
in line with our modeling results. Our methodology is intended only to 
identify those sites that have sufficiently poor ozone levels that 
there is clearly a reasonable expectation that an ozone nonattainment 
or maintenance problem will persist in the 2023 ozone season. Moreover, 
2023 is so near in time that recent measured ozone levels can be used 
to reasonably project whether an air quality problem is likely to 
persist. We view this approach to identifying additional receptors in 
2023 as the best means of responding to the comments on this issue in 
this action, while also identifying all transport receptors.
    For purposes of this action, we treat these violating monitors as 
an additional type of maintenance-only receptor. Because our modeling 
did not identify these sites as receptors, we do not believe it is 
sufficiently certain that these sites will be in nonattainment such 
that they should be considered nonattainment receptors. Rather, our 
authority for treating these sites as receptors in 2023 flows from the 
responsibility in CAA section 110(a)(2)(i)(I) to prohibit emissions 
that interfere with maintenance of the NAAQS. See, e.g., North 
Carolina, 531 F.3d at 910-11 (failing to give effect to the interfere 
with maintenance clause ``provides no protection for downwind areas 
that, despite EPA's predictions, still find themselves struggling to 
meet NAAQS due to upwind interference . . . .'') (emphasis added). 
Recognizing that no modeling can perfectly forecast the future, and ``a 
degree of imprecision is inevitable in tackling the problem of 
interstate air pollution,'' this approach in the Agency's judgement 
best balances the need to avoid both ``under-control'' and 
``overcontrol,'' EME Homer City, 572 U.S. at 523.
    We acknowledge that the traditional modeling plus monitoring 
methodology we used at proposal and in prior ozone transport rules 
would otherwise have identified such sites as being in attainment in 
2023. Despite the implications of the current measured data suggesting 
there will be a nonattainment problem at these sites in 2023, we cannot 
definitively establish that such sites will be in nonattainment in 2023 
in light of our modeling projections. In the face of this uncertainty, 
we regard our ability to consider such sites as receptors for purposes 
of good neighbor analysis under CAA section 110(a)(2)(D)(i)(I) to be a 
function of the requirement to prohibit emissions that interfere with 
maintenance of the NAAQS; even if an area may be technically in 
attainment, we have reliable information indicating that there is an 
identified risk that attainment will not in fact be achieved.

[[Page 36705]]

    However, because we did not identify this basis for receptor-
identification at proposal, in this final action we are only using this 
receptor category on a confirmatory basis. That is, for states that we 
find linked based on our traditional modeling-based methodology in 
2023, we find in this final analysis that the linkage at Step 2 is 
strengthened and confirmed if that state is also linked to one or more 
``violating monitor'' receptors. If a state is only linked to a 
violating-monitor receptor in this final analysis, we are deferring 
taking final action on that state's SIP submittal. This is the case for 
the State of Tennessee. Among the states that previously had their 
transport SIPs fully approved for the 2015 ozone NAAQS, the EPA has 
also identified a linkage to violating-monitor receptors for the State 
of Kansas. The EPA intends to further review its air quality modeling 
results and recent measured ozone levels, and we intend to address 
these states' good neighbor obligations as expeditiously as practicable 
in a future action.

E. Methodology for Projecting Future Year Ozone Design Values

    Consistent with the 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 and 2026. That is, the ratios of 
future year model predictions to base year model predictions are used 
to adjust ambient ozone design values \160\ 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 final rule is 
2016, measured data for 2014-2018 (i.e., design values for 2016, 2017, 
and 2018) were used to project average and maximum design values in 
2023 and 2026.
---------------------------------------------------------------------------

    \160\ 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 and 2026 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 \161\ surrounding the location of the monitoring site to 
calculate a Relative Response Factor (RRF) for that site.\162\ However, 
the guidance also notes that an alternative array of grid cells may be 
used in certain situations where local topographic or geographical 
feature (e.g., a large water body or a significant elevation change) 
may influence model response.
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    \161\ As noted in this section, each model grid cell is 12 x 12 
km.
    \162\ The relative response factor represents the change in 
ozone at a given site. To calculate the RRF, the 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) average ozone concentration and the 
future year (e.g., 2023 model run) average ozone concentration 
represents the relative response factor.
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    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, the 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).\163\ Specifically, in the WRF meteorological 
model those grid cells that are greater than 50 percent 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 limited due to the presence of overwater 
meteorology. Thus, for our modeling the 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 and 2026 design values using 
both the ``3 x 3'' and ``no-water'' approaches are provided in the 
docket for this final rule. For this final rule, the EPA is relying 
upon design values based on the ``no water'' approach for identifying 
nonattainment and maintenance receptors.\164\
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    \163\ https://www.mmm.ucar.edu/weather-research-and-forecasting-model.
    \164\ Using design values from the ``3 x 3'' approach, the 
maintenance-only receptor at site 550590019 in Kenosha County, WI 
would become a nonattainment receptor because the average design 
value with the ``3 x 3'' approach is 72.0 ppb versus 70.8 ppb with 
the ``no water'' approach. In addition, the maintenance-only 
receptor at site 090099002 in New Haven County, CT would become a 
nonattainment receptor using the ``3 x 3'' approach because the 
average design value with the ``3 x 3'' approach is 71.2 ppb versus 
70.5 ppb with the ``no water'' approach.
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    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.\165\ 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 2021, which are the 
most recent official measured design values at the time of this final 
rule. As noted earlier, the Agency is identifying nonattainment 
receptors in this rulemaking as those sites that are violating the 
NAAQS based on current

[[Page 36706]]

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 (i.e., ozone design values below the 
level of the 2015 ozone NAAQS) 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, 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 the 2015 
ozone NAAQS as part of this final rule.\166\
---------------------------------------------------------------------------

    \165\ 40 CFR part 50, appendix P--Interpretation of the Primary 
and Secondary National Ambient Air Quality Standards for Ozone.
    \166\ In addition, there are 71 monitoring sites in California 
with projected 2023 maximum design values above the NAAQS. With two 
exceptions, as described in section IV.F of this document, the 
Agency is not making a determination in this action that these 
monitors are ozone transport receptors. The two exceptions are the 
two monitoring sites that represent air quality impacts to lands of 
the Morongo and Pechanga tribes. As explained in footnote 110 supra, 
we treat these as transport receptors that are impacted by emissions 
from California.
---------------------------------------------------------------------------

    Table IV.D-1 contains the 2016-centered \167\ base period average 
and maximum 8-hour ozone design values, the 2023 base case average and 
maximum design values and the measured 2021 design values for the sites 
that are projected to be nonattainment receptors in 2023. Table IV.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 Air Quality Modeling Final Rule TSD.
---------------------------------------------------------------------------

    \167\ 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 IV.D-1--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2021 Design Values (ppb) at Projected Nonattainment
                                                                        Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 2016        2016
               Monitor ID                          State                    County             Centered    Centered      2023        2023        2021
                                                                                                average     maximum     Average     Maximum
--------------------------------------------------------------------------------------------------------------------------------------------------------
060650016...............................  CA                      Riverside.................        79.0        80.0        72.2        73.1          78
060651016...............................  CA                      Riverside.................        99.7       101.0        91.0        92.2          95
080350004...............................  CO                      Douglas...................        77.3          78        71.3        71.9          83
080590006...............................  CO                      Jefferson.................        77.3          78        72.8        73.5          81
080590011...............................  CO                      Jefferson.................        79.3          80        73.5        74.1          83
090010017...............................  CT                      Fairfield.................        79.3          80        71.6        72.2          79
090013007...............................  CT                      Fairfield.................        82.0          83        72.9        73.8          81
090019003...............................  CT                      Fairfield.................        82.7          83        73.3        73.6          80
481671034...............................  TX                      Galveston.................        75.7          77        71.5        72.8          72
482010024...............................  TX                      Harris....................        79.3          81        75.1        76.7          74
490110004...............................  UT                      Davis.....................        75.7          78        72.0        74.2          78
490353006...............................  UT                      Salt Lake.................        76.3          78        72.6        74.2          76
490353013...............................  UT                      Salt Lake.................        76.5          77        73.3        73.8          76
551170006...............................  WI                      Sheboygan.................        80.0          81        72.7        73.6          72
--------------------------------------------------------------------------------------------------------------------------------------------------------


Table IV.D-2--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2021 Design Values (ppb) at Projected Maintenance-Only
                                                                        Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 2016        2016
               Monitor ID                          State                    County             Centered    Centered      2023        2023        2021
                                                                                                average     maximum     Average     Maximum
--------------------------------------------------------------------------------------------------------------------------------------------------------
040278011...............................  AZ                      Yuma......................        72.3          74        70.4        72.1          67
080690011...............................  CO                      Larimer...................        75.7          77        70.9        72.1          77
090099002...............................  CT                      New Haven.................        79.7          82        70.5        72.6          82
170310001...............................  IL                      Cook......................        73.0          77        68.2        71.9          71
170314201...............................  IL                      Cook......................        73.3          77        68.0        71.5          74
170317002...............................  IL                      Cook......................        74.0          77        68.5        71.3          73
350130021...............................  NM                      Dona Ana..................        72.7          74        70.8        72.1          80
350130022...............................  NM                      Dona Ana..................        71.3          74        69.7        72.4          75
350151005...............................  NM                      Eddy......................        69.7          74        69.7        74.1          77
350250008...............................  NM                      Lea.......................        67.7          70        69.8        72.2          66
480391004...............................  TX                      Brazoria..................        74.7          77        70.4        72.5          75
481210034...............................  TX                      Denton....................        78.0          80        69.8        71.6          74
481410037...............................  TX                      El Paso...................        71.3          73        69.8        71.4          75
482010055...............................  TX                      Harris....................        76.0          77        70.9        71.9          77
482011034...............................  TX                      Harris....................        73.7          75        70.1        71.3          71
482011035...............................  TX                      Harris....................        71.3          75        67.8        71.3          71
530330023...............................  WA                      King......................        73.3          77        67.6        71.0          64
550590019...............................  WI                      Kenosha...................        78.0          79        70.8        71.7          74
551010020...............................  WI                      Racine....................        76.0          78        69.7        71.5          73
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 36707]]

    In total, in the 2023 base case there are a total of 33 projected 
modeling-based receptors nationwide including 14 nonattainment 
receptors in 9 different counties and 19 maintenance-only receptors in 
13 additional counties (Harris County, TX, has both nonattainment and 
maintenance-only receptors).\168\ Of the 14 nonattainment receptors in 
2023, 7 remain nonattainment receptors, 5 are projected to become 
maintenance-only receptors and 2 are projected to be in attainment in 
2026. Of the 19 maintenance-only receptors in 2023, 7 are projected to 
remain maintenance-only receptors and 12 are projected to be in 
attainment in 2026. The projected average and maximum design values in 
2026 for all receptors are included in the Air Quality Modeling Final 
Rule TSD.
---------------------------------------------------------------------------

    \168\ 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 
noted in the proposed rule, 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 final rule.
---------------------------------------------------------------------------

    Comment: EPA received comments saying that the projected design 
values for 2023 were biased low compared to recent measured data. 
Commenters noted that a number of monitoring sites that are projected 
to be below the NAAQS in 2023 based on EPA's modeling for the proposed 
rule are currently measuring nonattainment. Because 2023 is only a year 
later than the most recent measured data some commenters said that EPA 
should give greater weight to measured data when identifying downwind 
receptors.
    Response: Based on an analysis of model projections for 2023 and 
recent trends in measured data, the EPA agrees that current data 
indicate that there are monitoring sites at risk of continued 
nonattainment in 2023 even though the model projected average and 
maximum design values at these sites are below the NAAQS (i.e., sites 
that are not modeling-based receptors).\169\ Specifically, the EPA 
believes that monitoring sites with measured design values and 4th high 
maximum daily 8-hour average (MDA8) ozone based on 2021 and preliminary 
2022 data have the greatest risk of continuing to have a problem 
attaining the standard in 2023, even when the modeling projects these 
sites will attain. These criteria are sufficiently conservative that we 
avoid including monitoring sites that have measured nonattainment data 
in recent years but could reasonably be anticipated to not have a 
nonattainment or maintenance problem in 2023, in line with our modeling 
results. Our methodology is intended only to identify those sites that 
have sufficiently poor ozone levels that there is clearly a reasonable 
expectation that an ozone nonattainment or maintenance problem will 
persist in the 2023 ozone season. We do not apply this methodology for 
the 2026 analytic year, because that year is sufficiently farther in 
the future that we do not believe there would be a reasonable basis to 
supplement our modeling analysis with this ``violating monitor'' 
methodology. By comparison, 2023 is so near in time that recent 
measured ozone levels can be used reasonably to project whether an air 
quality problem is likely to persist. We view this approach to 
identifying additional receptors in 2023 as the best means of 
responding to the comments on this issue in this action. The monitoring 
sites that meet these criteria, along with the corresponding measured 
and modeled data, are provided in Table IV.D-3.
---------------------------------------------------------------------------

    \169\ In addition, we note that comparing the projected 2023 
maximum design values at modeling-based receptors listed in Table 
IV.D-1 and Table IV.D-2 to the 2021 design values measured at these 
sites indicates that the projected maximum values are lower than the 
measured data at most receptors. These differences are particularly 
evident at receptors in coastal Connecticut and in Denver. (See Air 
Quality Modeling Final Rule TSD for details).
---------------------------------------------------------------------------

    For purposes of this action, we will treat these sites as an 
additional type of maintenance-only receptor. Because our modeling did 
not identify these sites as receptors, we do not believe it is 
sufficiently certain that these sites will be in nonattainment that 
they should be considered nonattainment receptors for purposes of this 
final rule. Rather, our authority for treating these sites as receptors 
in 2023 flows from the responsibility in CAA section 110(a)(2)(i)(I) to 
prohibit emissions that interfere with maintenance of the NAAQS. See, 
e.g., North Carolina, 531 F.3d at 910-11 (failing to give effect to the 
interfere with maintenance clause ``provides no protection for downwind 
areas that, despite EPA's predictions, still find themselves struggling 
to meet NAAQS due to upwind interference . . . .'') (emphasis added). 
Recognizing that no modeling can perfectly forecast the future, and ``a 
degree of imprecision is inevitable in tackling the problem of 
interstate air pollution,'' this approach in the Agency's judgement 
best balances the need to avoid both ``under-control'' and 
``overcontrol,'' EME Homer City, 572 U.S. at 523.
    In this action, we identify ``violating monitor'' maintenance-only 
receptors for purposes of more firmly establishing that the states we 
have otherwise identified as linked at Step 2 in our modeling-based 
methodology can indeed be reasonably anticipated to be linked to air 
quality problems in downwind states in 2023 for reasons that extend 
beyond that methodology. In this sense, this approach is 
``confirmatory'' and does not alter the geography of the final rule 
compared to the application of the modeling-based receptor definitions 
used at proposal. Rather, it strengthens the analytical basis for our 
Step 2 findings by establishing that many upwind states covered in this 
action are also projected to contribute above 1 percent of the NAAQS to 
these types of receptors. For purposes of this final rule, we will not 
finalize FIPs for any states that this analysis indicates contribute 
greater than 1 percent of the NAAQS only to a ``violating monitor'' 
receptor. Our analysis suggests this would be the case for two states, 
Kansas and Tennessee (see section IV.F of this document).\170\ We are 
making no final decisions with respect to these states in this action 
and intend to address these states in a subsequent action.
---------------------------------------------------------------------------

    \170\ We have not conducted an analysis in this action to 
determine whether violating-monitor receptors may exist in 
California.

     Table IV.D-3--Average and Maximum 2023 Base Case 8-Hour Ozone, and 2021 and Preliminary 2022 Design Values (ppb) and 4th High Concentrations at
                                                                   Violating Monitors
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        2023        2023                           2021 4th   2022 P 4th
              Monitor ID                      State                  County            Average     Maximum     2021    2022 P *      high        high
--------------------------------------------------------------------------------------------------------------------------------------------------------
40070010.............................  AZ                   Gila...................        67.9        69.5       77          76          75          74

[[Page 36708]]

 
40130019.............................  AZ                   Maricopa...............        69.8        70.0       75          77          78          76
40131003.............................  AZ                   Maricopa...............        70.1        70.7       80          80          83          78
40131004.............................  AZ                   Maricopa...............        70.2        70.8       80          81          81          77
40131010.............................  AZ                   Maricopa...............        68.3        69.2       79          80          80          78
40132001.............................  AZ                   Maricopa...............        63.8        64.1       74          78          79          81
40132005.............................  AZ                   Maricopa...............        69.6        70.5       78          79          79          77
40133002.............................  AZ                   Maricopa...............        65.8        65.8       75          75          81          72
40134004.............................  AZ                   Maricopa...............        65.7        66.6       73          73          73          71
40134005.............................  AZ                   Maricopa...............        62.3        62.3       73          75          79          73
40134008.............................  AZ                   Maricopa...............        65.6        66.5       74          74          74          71
40134010.............................  AZ                   Maricopa...............        63.8        66.9       74          76          77          75
40137020.............................  AZ                   Maricopa...............        67.0        67.0       76          77          77          75
40137021.............................  AZ                   Maricopa...............        69.8        70.1       77          77          78          75
40137022.............................  AZ                   Maricopa...............        68.2        69.1       76          78          76          79
40137024.............................  AZ                   Maricopa...............        67.0        67.9       74          76          74          77
40139702.............................  AZ                   Maricopa...............        66.9        68.1       75          77          72          77
40139704.............................  AZ                   Maricopa...............        65.3        66.2       74          77          76          76
40139997.............................  AZ                   Maricopa...............        70.5        70.5       76          79          82          76
40218001.............................  AZ                   Pinal..................        67.8        69.0       75          76          73          77
80013001.............................  CO                   Adams..................        63.0        63.0       72          77          79          75
80050002.............................  CO                   Arapahoe...............        68.0        68.0       80          80          84          73
80310002.............................  CO                   Denver.................        63.6        64.8       72          74          77          71
80310026.............................  CO                   Denver.................        64.5        64.8       75          77          83          72
90079007.............................  CT                   Middlesex..............        68.7        69.0       74          73          78          73
90110124.............................  CT                   New London.............        65.5        67.0       73          72          75          71
170310032............................  IL                   Cook...................        67.3        69.8       75          75          77          72
170311601............................  IL                   Cook...................        63.8        64.5       72          73          72          71
181270024............................  IN                   Porter.................        63.4        64.6       72          73          72          73
260050003............................  MI                   Allegan................        66.2        67.4       75          75          78          73
261210039............................  MI                   Muskegon...............        67.5        68.4       74          79          75          82
320030043............................  NV                   Clark..................        68.4        69.4       73          75          74          74
350011012............................  NM                   Bernalillo.............        63.8        66.0       72          73          76          74
350130008............................  NM                   Dona Ana...............        65.6        66.3       72          76          79          78
361030002............................  NY                   Suffolk................        66.2        68.0       73          74          79          74
390850003............................  OH                   Lake...................        64.3        64.6       72          74          72          76
480290052............................  TX                   Bexar..................        67.1        67.8       73          74          78          72
480850005............................  TX                   Collin.................        65.4        66.0       75          74          81          73
481130075............................  TX                   Dallas.................        65.3        66.5       71          71          73          72
481211032............................  TX                   Denton.................        65.9        67.7       76          77          85          77
482010051............................  TX                   Harris.................        65.3        66.3       74          73          83          72
482010416............................  TX                   Harris.................        68.8        70.4       73          73          78          71
484390075............................  TX                   Tarrant................        63.8        64.7       75          76          76          77
484391002............................  TX                   Tarrant................        64.1        65.7       72          77          76          80
484392003............................  TX                   Tarrant................        65.2        65.9       72          72          74          72
484393009............................  TX                   Tarrant................        67.5        68.1       74          75          75          75
490571003............................  UT                   Weber..................        69.3        70.3       71          74          77          71
550590025............................  WI                   Kenosha................        67.6        70.7       72          73          72          71
550890008............................  WI                   Ozaukee................        65.2        65.8       71          72          72          72
--------------------------------------------------------------------------------------------------------------------------------------------------------
* 2022 preliminary design values are based on 2022 measured MDA8 concentrations provided by state air agencies to the EPA's Air Quality System (AQS), as
  of January 3, 2023.

F. 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 \171\ to quantify the contribution of 2023 and 2026 base case 
NOX and VOC emissions from all sources in each state to the

[[Page 36709]]

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. 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).
---------------------------------------------------------------------------

    \171\ 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 runs, 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 2016v3 emissions 
modeling platform (EPA did not model the contributions from individual 
tribes);
     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.\172\
---------------------------------------------------------------------------

    \172\ 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. The monitoring site in Seattle, King County, Washington 
(530330023), was the only receptor which did not meet this 
criterion.
---------------------------------------------------------------------------

    This same approach was applied to calculate contribution metric 
values at individual monitoring sites for 2026.\173\
---------------------------------------------------------------------------

    \173\ 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 final 
rule. Additional details on the source apportionment modeling and the 
procedures for calculating contributions can be found in the Air 
Quality Modeling Final Rule TSD. The EPA's response to comments on the 
method for calculating the contribution metric can be found in the RTC 
document for this final rule.
    The largest contribution from each state that is the subject of 
this rule to modeled 8-hour ozone nonattainment and maintenance 
receptors in downwind states in 2023 and 2026 are provided in Table 
IV.F-1 and Table IV.F-2, respectively. The largest contribution from 
each state to a ``violating monitor'' maintenance-only receptor is 
provided in Table IV.F-3.

       Table IV.F-1--Largest Contribution to Downwind 8-Hour Ozone
             Nonattainment and Maintenance Receptors in 2023
                                  [ppb]
------------------------------------------------------------------------
                                        Largest             Largest
                                    contribution to     contribution to
          Upwind state                 downwind            downwind
                                     nonattainment     maintenance-only
                                       receptors           receptors
------------------------------------------------------------------------
Alabama.........................                0.75                0.65
Arizona.........................                0.54                1.69
Arkansas........................                0.94                1.21
California......................               35.27                6.31
Colorado........................                0.14                0.18
Connecticut.....................                0.01                0.01
Delaware........................                0.44                0.56
District of Columbia............                0.03                0.04
Florida.........................                0.50                0.54
Georgia.........................                0.18                0.17
Idaho...........................                0.42                0.41
Illinois........................               13.89               19.09

[[Page 36710]]

 
Indiana.........................                8.90               10.03
Iowa............................                0.67                0.90
Kansas..........................                0.46                0.52
Kentucky........................                0.84                0.79
Louisiana.......................                9.51                5.62
Maine...........................                0.02                0.01
Maryland........................                1.13                1.28
Massachusetts...................                0.33                0.15
Michigan........................                1.59                1.56
Minnesota.......................                0.36                0.85
Mississippi.....................                1.32                0.91
Missouri........................                1.87                1.39
Montana.........................                0.08                0.10
Nebraska........................                0.20                0.36
Nevada..........................                1.11                1.13
New Hampshire...................                0.10                0.02
New Jersey......................                8.38                5.79
New Mexico......................                0.36                1.59
New York........................               16.10               11.29
North Carolina..................                0.45                0.66
North Dakota....................                0.18                0.45
Ohio............................                2.05                1.98
Oklahoma........................                0.79                1.01
Oregon *........................                0.46                0.31
Pennsylvania....................                6.00                4.36
Rhode Island....................                0.04                0.01
South Carolina..................                0.16                0.18
South Dakota....................                0.05                0.08
Tennessee.......................                0.60                0.68
Texas...........................                1.03                4.74
Utah............................                1.29                0.98
Vermont.........................                0.02                0.01
Virginia........................                1.16                1.76
Washington......................                0.16                0.09
West Virginia...................                1.37                1.49
Wisconsin.......................                0.21                2.86
Wyoming.........................                0.68                0.67
------------------------------------------------------------------------


       Table IV.F-2--Largest Contribution to Downwind 8-Hour Ozone
             Nonattainment and Maintenance Receptors in 2026
                                  [ppb]
------------------------------------------------------------------------
                                        Largest             Largest
                                    contribution to     contribution to
          Upwind state                 downwind            downwind
                                     nonattainment     maintenance-only
                                       receptors           receptors
------------------------------------------------------------------------
Alabama.........................                0.20                0.69
Arizona.........................                0.44                1.34
Arkansas........................                0.53                1.16
California......................               34.03                6.16
Colorado........................                0.04                0.17
Connecticut.....................                0.00                0.01
Delaware........................                0.43                0.41
District of Columbia............                0.03                0.02
Florida.........................                0.46                0.17
Georgia.........................                0.13                0.16
Idaho...........................                0.27                0.36
Illinois........................                0.63               13.57
Indiana.........................                1.06                8.53
Iowa............................                0.14                0.62
Kansas..........................                0.14                0.42
Kentucky........................                0.79                0.76
Louisiana.......................                4.57                9.37

[[Page 36711]]

 
Maine...........................                0.00                0.01
Maryland........................                1.06                0.92
Massachusetts...................                0.06                0.31
Michigan........................                1.39                1.47
Minnesota.......................                0.15                0.32
Mississippi.....................                0.29                1.15
Missouri........................                0.29                1.68
Montana.........................                0.06                0.07
Nebraska........................                0.09                0.19
Nevada..........................                0.67                0.90
New Hampshire...................                0.01                0.09
New Jersey......................                8.10                7.04
New Mexico......................                0.35                0.46
New York........................               12.65               12.34
North Carolina..................                0.40                0.42
North Dakota....................                0.09                0.17
Ohio............................                1.95                1.93
Oklahoma........................                0.19                0.74
Oregon *........................                0.26                0.41
Pennsylvania....................                5.47                4.94
Rhode Island....................                0.00                0.03
South Carolina..................                0.14                0.15
South Dakota....................                0.03                0.04
Tennessee.......................                0.24                0.54
Texas...........................                0.48                4.34
Utah............................                1.05                0.81
Vermont.........................                0.01                0.02
Virginia........................                1.09                1.10
Washington......................                0.10                0.14
West Virginia...................                1.36                1.34
Wisconsin.......................                0.17                0.18
Wyoming.........................                0.40                0.59
------------------------------------------------------------------------


 Table IV.F-3--Largest Contribution to Downwind 8-Hour Ozone ``Violating
                  Monitor'' Maintenance-Only Receptors
                                  [ppb]
------------------------------------------------------------------------
                                                    Largest contribution
                                                         to downwind
                   Upwind state                       violating monitor
                                                      maintenance-only
                                                          receptors
------------------------------------------------------------------------
Alabama...........................................                  0.79
Arizona...........................................                  1.62
Arkansas..........................................                  1.16
California........................................                  6.97
Colorado..........................................                  0.39
Connecticut.......................................                  0.17
Delaware..........................................                  0.42
District of Columbia..............................                  0.03
Florida...........................................                  0.50
Georgia...........................................                  0.31
Idaho.............................................                  0.46
Illinois..........................................                 16.53
Indiana...........................................                  9.39
Iowa..............................................                  1.13
Kansas............................................                  0.82
Kentucky..........................................                  1.57
Louisiana.........................................                  5.06
Maine.............................................                  0.02
Maryland..........................................                  1.14
Massachusetts.....................................                  0.39
Michigan..........................................                  3.47

[[Page 36712]]

 
Minnesota.........................................                  0.64
Mississippi.......................................                  1.02
Missouri..........................................                  2.95
Montana...........................................                  0.12
Nebraska..........................................                  0.43
Nevada............................................                  1.11
New Hampshire.....................................                  0.10
New Jersey........................................                  8.00
New Mexico........................................                  0.34
New York..........................................                 12.08
North Carolina....................................                  0.65
North Dakota......................................                  0.35
Ohio..............................................                  2.25
Oklahoma..........................................                  1.57
Oregon *..........................................                  0.36
Pennsylvania......................................                  5.20
Rhode Island......................................                  0.08
South Carolina....................................                  0.23
South Dakota......................................                  0.12
Tennessee.........................................                  0.86
Texas.............................................                  3.83
Utah..............................................                  1.46
Vermont...........................................                  0.03
Virginia..........................................                  1.39
Washington........................................                  0.11
West Virginia.....................................                  1.79
Wisconsin.........................................                  5.10
Wyoming...........................................                  0.42
------------------------------------------------------------------------
* Does not include California monitoring sites.

2. Application of Contribution Screening Threshold
    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 Air Quality Modeling Final Rule TSD.
    The EPA applies an air quality screening threshold of 1 percent of 
the NAAQS, which has been used since the CSAPR rulemaking, including in 
the CSAPR Update, the Revised CSAPR Update, and numerous actions 
evaluating states' transport SIP submittals. The explanation for how 
this value was originally derived is available in the CSAPR rulemaking 
from 2011. See 76 FR 48208, 48237-38. As originally explained there, 
the application of a relatively low threshold is intended to capture a 
relatively large percentage of the contribution from upwind states to 
downwind receptors in light of the regional-scale, collective 
contribution problem associated with both ozone and PM2.5 
NAAQS. Id. The Agency also explained that the use of a higher threshold 
in transport rules prior to CSAPR was based on single-day maximum 
contribution, whereas in CSAPR (and continuing in subsequent rules 
including this one), the Agency uses a more robust, average 
contribution metric over multiple days. Thus, it was not the case that 
1 percent of NAAQS was substantially more stringent than that prior 
approach. Id. at 48238. In the 2016 CSAPR Update, the EPA reviewed the 
1 percent threshold (as coupled with multi-day averaging) and 
determined it was appropriate to continue to apply this threshold. The 
EPA compared the 1 percent threshold to a 0.5 percent of NAAQS 
threshold and a 5 percent of NAAQS threshold. The EPA found that the 
lower threshold did not capture appreciably more upwind state 
contribution compared to the 1 percent threshold, while the 5 percent 
threshold allowed too much upwind state contribution to drop out from 
further analysis.\174\ The EPA continues to observe that nonattainment 
and maintenance receptors identified at Step 1 are impacted 
collectively by emissions from numerous upwind contributors. Therefore, 
application of a low, uniform screening threshold allows the EPA to 
identify upwind states that share a responsibility under the interstate 
transport provision to eliminate their significant contribution.
---------------------------------------------------------------------------

    \174\ See Final CSAPR Update Air Quality Modeling TSD, at 27-30 
(EPA-HQ-OAR-2015-0596-0144). See also 86 FR 23054, 23085.
---------------------------------------------------------------------------

    As we explained at proposal, 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.\175\ (The 
memorandum also indicated that any

[[Page 36713]]

higher alternative threshold, such as 2 ppb, would likely not be 
appropriate.) The EPA nonetheless proposed to fulfill its role under 
CAA section 110(c) in promulgating FIPs to directly implement good 
neighbor requirements, and in this role, proposed retaining use of the 
1 percent threshold for all states. We noted that in several documents 
proposing transport SIP disapprovals, see, e.g., 87 FR 9498 and 87 FR 
9510 (Feb. 22, 2022), we explained that our experience since the 
issuance of the August 2018 memorandum regarding use of alternative 
thresholds led the Agency to 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.
---------------------------------------------------------------------------

    \175\ August 2018 memo at 4.
---------------------------------------------------------------------------

    We went on to explain that the 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. Using multiple different 
thresholds at Step 2 with respect to the 2015 ozone NAAQS raises 
substantial policy consistency and practical implementation 
concerns.\176\ The application of different thresholds at Step 2 has 
the potential to result in inconsistent determination 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. We explained that while 
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 
alternative thresholds would allow certain states to avoid further 
evaluation of potential emissions controls while other states must 
proceed to a Step 3 analysis. This could create significant equity and 
consistency problems among states.
---------------------------------------------------------------------------

    \176\ 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.
---------------------------------------------------------------------------

    The EPA further proposed that, in promulgating FIPs to address 
these obligations on a nationwide scale, national ozone transport 
policy would not be well-served by applying a single, less stringent 
threshold 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 noted at proposal that while this 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. Considering 
the core statutory objective of ensuring elimination of all significant 
contribution to nonattainment or interference of the NAAQS in downwind 
states and the broad, regional nature of the collective contribution 
problem with respect to ozone, EPA could not identify a compelling 
policy imperative to move to a 1 ppb threshold.
    In the proposal, we also found 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 protective ozone NAAQS) to be an important 
consideration. 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 protective NAAQS.
    The Agency also questioned whether it would 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 the possibility of an 
alternative threshold in the August 2018 memorandum, the EPA concluded 
in the proposal that our experience and further evaluation since the 
issuance of that memo has revealed substantial programmatic and policy 
difficulties in attempting to implement this approach, and therefore we 
proposed to apply the 1 percent of NAAQS threshold.
    Comment: Many commenters disagreed with our proposal to continue 
using a 1 percent of NAAQS threshold. They argued that the EPA was 
reversing course from its policy as articulated in the August 2018 
memorandum and that the EPA was now bound to use a 1 ppb threshold 
rather than 1 percent of NAAQS, even in promulgating a FIP rather than 
evaluating SIPs. Commenters further argued that a 1 ppb threshold would 
be more consistent with the EPA's ``significant impact level'' (SIL) 
guidance related to implementing prevention of significant 
deterioration (PSD) permitting requirements. They argued that the 1 
percent threshold was below precision limits of regulatory ozone 
monitors, and they argued it was within the ``margin of error'' of the 
EPA's modeling.
    Response: The EPA is finalizing its proposed approach of 
consistently using a 1 percent of the NAAQS threshold at Step 2 in this 
action to determine which states contribute to identified nonattainment 
and maintenance receptors. This approach ensures both national 
consistency across all states and consistency and continuity with our 
prior interstate transport actions for other NAAQS. We do not agree 
that this approach is inconsistent with or a reversal in policy from 
the August 2018 memorandum, which only suggested that states in the 
development of their SIPs ``may'' be able to establish that 1 ppb could 
be an appropriate alternative threshold. The EPA has been consistent in 
that memorandum, and since that time, that final determinations on 
alternative thresholds would be made through rulemaking action, as the 
EPA is taking here.
    The August 2018 memorandum made clear that the Agency had 
substantial doubts that any threshold greater than 1 ppb (such as 2 
ppb) would be acceptable, and the Agency is affirming that a threshold 
higher than 1 ppb would not be justified under any circumstance for 
purposes of this action. No commenter credibly provided a basis for 
using a threshold even higher than 1 ppb, and so this issue is 
primarily limited to the difference between a 0.7 ppb threshold (the 1 
percent of the NAAQS threshold discussed previously in this section) 
and a 1.0 ppb threshold. Therefore, before proceeding in responding to 
these comments, we note that this issue is only relevant to a small 
number of states whose contributions to any receptor are above 1 
percent of the NAAQS but lower than 1 ppb. Under the 2016v3 modeling of 
2023 being used in this final rule, the states in this rule with 
contributions that fall between 0.70 ppb and 1 ppb are Alabama, 
Kentucky, and Minnesota. Similarly, the EPA applies the 1 percent 
threshold in its 2026 modeling projections to determine if any states 
will not be linked to an ozone receptor by that year, and therefore 
should not be subject to the more stringent requirements that take 
effect in 2026. The states in this rule in that year with contribution 
between 0.70 ppb and 1 ppb are

[[Page 36714]]

Kentucky, Nevada, and Oklahoma. For all other states covered in this 
action, at least one linkage exists in 2023 (and, as relevant, in 2026) 
that is greater than 1 ppb, and therefore the question of whether the 
EPA must recognize a 1 ppb threshold would not have a dispositive 
effect on the regulatory determination being made at Step 2.
    The 1 percent of the NAAQS threshold is consistent with the Step 2 
approach that the EPA applied in CSAPR for the 1997 ozone NAAQS and has 
subsequently been applied in the CSAPR Update and Revised CSAPR Update 
when evaluating determining interstate transport obligations for the 
2008 ozone NAAQS. The EPA continues to find 1 percent of the ozone 
NAAQS to be an appropriate threshold. For ozone, as the EPA found in 
CAIR, CSAPR, and the CSAPR Update, a portion of the nonattainment and 
maintenance problems in the U.S. results from the combined impact of 
relatively small contributions from many upwind states, along with 
contributions from in-state sources and other sources. The EPA's 
analysis shows that the ozone transport problem being analyzed in this 
rule is still the result of the collective impacts of emissions from 
multiple upwind contributors. Therefore, application of a consistent 
contribution threshold is necessary to identify those upwind states 
that should have responsibility for addressing their contribution (to 
the extent found ``significant'' at Step 3) to the downwind 
nonattainment and maintenance problems to which they collectively 
contribute. Where a great number of geographically dispersed emissions 
sources contribute to a downwind air quality problem, which is the case 
for ozone, EPA believes that, in the context of CAA section 
110(a)(2)(D)(i)(I), a state-level threshold of 1 percent of the NAAQS 
is a reasonably small enough value to identify only the greater-than-de 
minimis contributors yet is not so large that it unfairly focuses 
attention for further action only on the largest single or few upwind 
contributors. Continuing to use 1 percent of the NAAQS as the screening 
metric to evaluate collective contribution from many upwind states also 
allows the EPA (and states) to apply a consistent framework to evaluate 
interstate emissions transport under the interstate transport provision 
from one NAAQS to the next. See 86 FR 23054, 23085; 81 FR 74504, 74518; 
76 FR 48208, 48237-38.
    Further, the EPA notes that the role of the Step 2 threshold is 
limited and just one step in the larger 4-Step Framework. It serves to 
screen in states for further evaluation of emissions control 
opportunities applying a multifactor analysis at Step 3. Thus, as the 
Supreme Court has recognized, the contribution threshold essentially 
functions to exclude states with ``de miminis'' impacts. EME Homer 
City, 572 U.S. 489, 500.
    Comments related to the August 2018 memorandum argued that the EPA 
legally committed itself to approving SIP submissions from states with 
contributions below 1 ppb and so now the EPA must apply that threshold 
in this FIP action. (Comments regarding this issue as related to the 
EPA's action on SIPs is addressed in that rulemaking and is beyond the 
scope of this action.) This is not what the memorandum said. The 
memorandum merely provided an analysis regarding ``the degree to which 
certain air quality threshold amounts capture the collective amount of 
upwind contribution from upwind states.'' \177\ It interpreted ``that 
information to make recommendations about what thresholds may be 
appropriate for use in'' SIP submissions (emphasis added).\178\ 
Specifically, the August 2018 memorandum said, ``Because the amount of 
upwind collective contribution capture with the 1 percent and the 1 ppb 
thresholds is generally comparable, overall, we believe it may be 
reasonable and appropriate for states to use a 1 ppb contribution 
threshold, as an alternative to a 1 percent threshold, at Step 2 of the 
4-step framework in developing their SIP revisions addressing the good 
neighbor provision for the 2015 ozone NAAQS'' (emphasis added).\179\ 
Thus, the text of the August 2018 memorandum in no way committed that 
the EPA would be using a 1 ppb threshold going forward either in its 
evaluation of SIPs or in promulgating a FIP. The August 2018 memorandum 
indicated that ``[f]ollowing these recommendations does not ensure that 
EPA will approve a SIP revision in all instances where the 
recommendations are followed, as the guidance may not apply to the 
facts and circumstances underlying a particular SIP. Final decisions by 
the EPA to approve a particular SIP revision will only be made based on 
the requirements of the statute and will only be made following an air 
agency's final submission of the SIP revision to the EPA, and after 
appropriate notice and opportunity for public review and comment.'' 
\180\ Further, the August 2018 memorandum said that ``EPA and air 
agencies should consider whether the recommendations in this guidance 
are appropriate for each situation.'' \181\ The memorandum said nothing 
regarding what threshold the EPA would apply if promulgating a FIP.
---------------------------------------------------------------------------

    \177\ August 2018 memorandum, at 1.
    \178\ Id.
    \179\ Id. at 4.
    \180\ Id. at 1.
    \181\ Id.
---------------------------------------------------------------------------

    As explained in the SIP disapproval action and again here, the EPA 
finds it would not be sound policy to apply an alternative contribution 
threshold or thresholds to one or more states within the 4-step 
interstate transport framework for the 2015 ozone NAAQS. However, the 
EPA disagrees with commenters' claims that the agency has reversed 
course on applying the August 2018 memorandum, because the memorandum 
never adopted a view that the use of 1 ppb or other alternative 
thresholds would in fact be acceptable. Although the EPA said at 
proposal that the EPA may rescind the guidance in the future, we took 
comment on the subject and also stated, ``EPA is not at this time 
rescinding the August 2018 memorandum.'' \182\ The EPA is not formally 
rescinding the August 2018 memorandum in this action or at this time. 
However, it is not required that agencies must ``rescind'' a memorandum 
or guidance the moment it becomes outdated or called into question. The 
August 2018 memorandum was not issued through notice-and-comment 
rulemaking and is not binding on the Agency or other parties. While the 
willingness of the Agency as expressed in that memorandum to entertain 
the possibility of an alternative threshold of 1 ppb may be considered 
a kind of policy position, agencies may change their non-binding 
policies without going through notice and comment rulemaking. Catawba 
County v. EPA, 571 F.3d 20, 34 (D.C. Cir. 2009). In this case, we went 
through notice and comment rulemaking on this topic in the SIP-
disapproval action (88 FR 9336) and here, even though the August 2018 
memorandum was issued without such opportunity for public input. We 
further address the basis for the consistent use of a 1 percent of 
NAAQS threshold and summarize our conclusions under the FCC v. Fox 
factors below.
---------------------------------------------------------------------------

    \182\ 87 FR 9545, 9551 (Feb. 22, 2022) (Alabama, Mississippi, 
Tennessee); 87 FR 9498, 9510 (Feb. 22, 2022) (Kentucky); 87 FR 9838, 
9844 (Feb. 22, 2022) (Illinois, Indiana, Michigan, Minnesota, Ohio, 
Wisconsin); 87 FR 9798, 9807, 9813, 9820 (Feb. 22, 2022) (Arkansas, 
Louisiana, Oklahoma, Texas); 87 FR 9533, 9542 (Feb. 22, 2022) 
(Missouri); 87 FR 31470, 31479 (May 24, 2022) (Utah); 87 FR 31495, 
31504 (May 24, 2022) (Wyoming); 87 FR 31485, 31490 (May 24, 2022) 
(Nevada).
---------------------------------------------------------------------------

    We continue to believe, as set forth in our proposed action, that 
national ozone transport policy is not well served by

[[Page 36715]]

allowing for less protective thresholds than 1 percent of the NAAQS at 
Step 2. Furthermore, the EPA disagrees with commenters who suggest that 
national consistency is an inappropriate consideration in the context 
of interstate ozone transport. The Good Neighbor provision, CAA section 
110(a)(2)(D)(i)(I), requires to a unique degree of concern for 
consistency, parity, and equity across state lines.\183\ For a regional 
air pollutant such as ozone, consistency in requirements and 
expectations across all states is essential. Based on the EPA's review 
of good neighbor SIP submissions to-date and after further 
consideration of the policy implications of attempting to recognize an 
alternative Step 2 threshold for certain states, the Agency concludes 
that the attempted use of different thresholds at Step 2 with respect 
to the 2015 8-hour ozone NAAQS raises substantial policy consistency 
and practical implementation concerns. The availability of different 
thresholds at Step 2 has the potential to result in inconsistent 
application of good neighbor obligations based solely on the strength 
of a state's SIP submission at Step 2 of the 4-step interstate 
transport framework. The steps of the analysis that lead up to 
evaluating emissions reductions opportunities to address states' 
significant contribution at Step 3 should be applied on a consistent 
basis. 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 and could lead to ineffective or 
inefficient approaches to eliminating significant contribution.
---------------------------------------------------------------------------

    \183\ EPA notes that Congress has placed on 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.
---------------------------------------------------------------------------

    One commenter suggested the EPA could address this potentially 
inequitable outcome by simply adopting a 1 ppb contribution threshold 
for all states. However, the August 2018 memorandum did not conclude 
that 1 ppb would be appropriate for all states and the EPA does not 
view that conclusion to be supported at present. The EPA recognized in 
the August 2018 memorandum that there was some similarity in the amount 
of total upwind contribution captured (on a nationwide basis) between 1 
percent and 1 ppb. However, while this may be true in some sense, that 
is hardly a compelling basis to move to a 1 ppb threshold for every 
state. 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 memorandum; 
in the EPA's 2016v2 modeling, the amount lost is 5 percent; in the 
EPA's 2016v3 modeling used for final, the amount lost is also 5 
percent). Further, this logic has no end point. A similar observation 
could be made with respect to any incremental change. For example, 
should the EPA next recognize a 1.2 ppb threshold because that would 
only cause some small additional loss in capture of upwind state 
contribution as compared to 1 ppb? If the only basis for moving to a 1 
ppb threshold is that it captures a ``similar'' (but actually smaller) 
amount of upwind contribution, then there is no basis for moving to 
that threshold at all. Considering the core statutory objective of 
ensuring elimination of all significant contribution to nonattainment 
or interference with maintenance of the NAAQS in other states and the 
broad, regional nature of the collective contribution problem with 
respect to ozone, we continue to find no compelling policy reason to 
adopt a new threshold for all states of 1 ppb.
    Nor have commenters explained why use of a 1 ppb threshold would be 
appropriate under the more protective 2015 ozone NAAQS when a 1 percent 
of the NAAQS contribution threshold has been used for less protective 
ozone NAAQS. To illustrate, a state contributing greater than 0.75 ppb 
but less than 1 ppb to a receptor under the 2008 ozone NAAQS was 
``linked'' at Step 2,\184\ but if a 1 ppb threshold were used for the 
2015 ozone NAAQS then that same state would not be ``linked'' to a 
receptor at Step 2 under a NAAQS that is set to be more protective of 
human health and the environment. Consistency with past interstate 
transport actions such as CSAPR, and the CSAPR Update and Revised CSAPR 
Update rulemakings (which all used the 1 percent of the NAAQS for less 
protective ozone NAAQS), is an important consideration. We affirm our 
view in CSAPR that continuing to use a 1 percent of NAAQS approach 
ensures that if 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. See 76 
FR 48208, 48237-38.
---------------------------------------------------------------------------

    \184\ See 86 FR 23054, 23058 (April 30, 2021).
---------------------------------------------------------------------------

    We note further that application of a 1 percent of NAAQS threshold 
has been the EPA's consistent approach in each of our notice-and-
comment rulemakings beginning with CSAPR and continuing with the CSAPR 
Update, the Revised CSAPR Update, and numerous actions on ozone 
transport SIP submissions. In each case, the 1 percent of the NAAQS 
threshold was subject to rigorous vetting through public comment and 
the Agency's response to those comments, including through the use of 
analytical evaluations of alternative thresholds. See, e.g., 81 FR 
74518-19. By contrast, the August 2018 memorandum was not issued 
through notice-and-comment rulemaking procedures, and the EPA was 
careful to caveat its utility and ultimate reliability for that reason.
    The EPA disagrees with claims that the EPA is applying the August 
2018 memorandum inconsistently based on the EPA's actions with regard 
to Arizona, Iowa, and Oregon. The EPA withdrew a previously proposed 
approval of Iowa's SIP submission that was premised on a 1 ppb 
contribution threshold, and re-proposed and finalized approval of that 
SIP based on a different rationale using a 1 percent of the NAAQS 
contribution threshold. 87 FR 9477 (Feb. 22, 2022); 87 FR 22463 (April 
15, 2022). The EPA also disagrees with any claim that Oregon and 
Arizona were ``allowed'' to use a 1 ppb or higher threshold. The EPA 
approved Oregon's SIP submission for the 2015 ozone NAAQS on May 17, 
2019, and both Oregon and the EPA relied on a 1 percent of the NAAQS 
contribution threshold. 84 FR 7854, 7856 (March 5, 2019) (proposal); 84 
FR 22376 (May 17, 2019) (final). In the proposal for this action, the 
EPA explained it was not proposing to conduct an error correction for 
Oregon even though updated modeling indicated Oregon contributed above 
1 percent of the NAAQS to monitors in California.
    The EPA is deferring finalizing a finding at this time for Oregon 
(see section IV.G of this document for additional information). In 
2016, the EPA approved Arizona's SIP for the earlier 2008 ozone NAAQS 
based on a similar rationale with regard to certain monitors in 
California. 81 FR 15200 (March 22, 2016) (proposal); 81 FR 31513 (May 
19, 2016) (final rule). We are deferring finalizing a finding at this 
time that such a rationale is appropriate

[[Page 36716]]

with respect to the more protective 2015 ozone NAAQS. While Arizona and 
Oregon's interstate transport obligations for the 2015 ozone NAAQS 
remain pending (along with several other states), there is no 
inconsistency in the treatment of these states or any other state at 
Step 2.
    Some commenters claim the EPA must use a 1 ppb threshold based on 
the identification of 1 ppb as a significance threshold in one step of 
the PSD permitting process. The EPA's SIL guidances, however, relate to 
a different provision of the Clean Air Act regarding implementation of 
the prevention of significant deterioration (PSD) permitting program. 
This program applies in areas that have been designated attainment of 
the NAAQS and is intended to ensure that such areas remain in 
attainment even if emissions were to increase as a result of new 
sources or major modifications to existing sources located in those 
areas. This purpose is different than the purpose of the good neighbor 
provision, which is to assist downwind areas (in some cases hundreds or 
thousands of miles away) in resolving ongoing nonattainment of the 
NAAQS or difficulty maintaining the NAAQS through eliminating the 
emissions from other states that are significantly contributing to 
those problems. In addition, as discussed in preceding paragraphs, the 
purpose of the Step 2 threshold within the EPA's interstate transport 
framework for ozone is to broadly sweep in all states contributing to 
identified receptors above a de minimis level in recognition of the 
collective-contribution problem associated with regional-scale ozone 
transport. The threshold used in the context of PSD SIL serves a 
different purpose, and so it does not follow that they should be made 
equivalent. Further, commenters incorrectly associate the EPA's Step 2 
contribution threshold with the identification of ``significant'' 
emissions (which does not occur until Step 3), and so it is not the 
case that the EPA is interpreting the same term differently.
    The EPA has previously explained this distinction between the good 
neighbor framework and PSD SILs. See 70 FR 25162, 25190-25191 (May 12, 
2005); 76 FR 48208, 48237 (Aug. 8, 2011). Importantly, the implication 
of the PSD SIL threshold is not that single-source contribution below 
this level indicates the absence of a contribution or that no emissions 
control requirements are warranted. Rather, the PSD SIL threshold 
addresses whether further, more comprehensive, multi-source review or 
analysis of air quality impacts are required of the source to support a 
demonstration that it meets the criteria for a permit. A source with 
estimated impacts below the PSD SIL may use this to demonstrate that it 
will not cause or contribute (as those terms are used within the PSD 
program) to a violation of an ambient air quality standard, but is 
still subject to meeting applicable control requirements, including 
best available control technology, designed to moderate the source's 
impact on air quality.
    Moreover, other aspects of the technical methodology in the SILs 
guidance compared to the good neighbor framework make a direct 
comparison between these two values misleading. For instance, in PSD 
permit modeling using a single year of meteorology the maximum single-
day 8-hour contribution is evaluated with respect to the SIL. The 
purpose of the contribution threshold at Step 2 of the 4-step good 
neighbor framework is to determine whether the average contribution 
from a collection of sources in a state is small enough not to warrant 
any additional control for the purpose of mitigating interstate 
transport, even if that control were highly cost effective. Using a 1 
percent of the NAAQS threshold is more appropriate for evaluating 
multi-day average contributions from upwind states than a 1 ppb 
threshold applied for a single day, since that lower value of 1 percent 
of the NAAQS will capture variations in contribution. If EPA were to 
use a single day reflecting the maximum amount of contribution from an 
upwind state to determine whether a linkage exists at Step 2, 
commenters' arguments for use of the PSD SIL might have more force. 
This would in effect be a return to the pre-CSAPR contribution 
calculation methodology of using a single day, see 76 FR 48238. 
However, that would likely cause more states to become linked, not 
less. And in any case, consistent with the method in our modeling 
guidance for projecting future attainment/nonattainment and as the EPA 
concluded in 2011 in CSAPR, the present good neighbor methodology of 
using multiple days provides a more robust approach to establishing 
that a linkage exists at the state level than relying on a single day 
of data.
    A commenter also claimed the 1 percent of NAAQS threshold is 
inconsistent with the standards of precision for Federal reference 
monitors for ozone and the rounding requirements found in 40 CFR part 
50, appendix U, Interpretation of the Primary and Secondary National 
Ambient Air Quality Standards for Ozone. Commenter claimed that the 1 
percent contribution threshold of 0.7 ppb is lower than the 
manufacturer's reported precision of these reference monitors and that 
the requirements found in Appendix U truncates monitor values of 0.7 
ppb to 0 ppb. However, the commenter is mistaken in applying criteria 
related to the precision of monitoring technology to the modeling 
methodology by which we project contributions when quantifying and 
evaluating interstate transport at Step 2. Indeed, contributions by 
source or state cannot be derived from the total ambient concentration 
of ozone at a monitor at all but must be apportioned through modeling. 
Under our longstanding methodology for doing so, the contribution 
values identified from upwind states are based on a robust assessment 
of the average impact of each upwind state's ozone-precursor emissions 
over a range of scenarios, as explained in the 2016v3 modeling's Air 
Quality Modeling Final Rule TSD, in the docket for this rule, Docket ID 
No. EPA-HQ-OAR-2021-0668. This analysis is in no way connected with or 
dependent on monitoring instruments' precision of measurement. See EME 
Homer City, 795 F.3d 118, 135-36 (``[A] model is meant to simplify 
reality in order to make it tractable.' '') (quoting Chemical 
Manufacturers Association v. EPA, 28 F.3d 1259, 1264 (D.C. Cir. 1994).
    To the extent that commenters argue that the EPA consider a less 
stringent threshold as a result of modeling uncertainty, the EPA 
disagrees with this notion. The EPA has successfully applied a 1 
percent of NAAQS threshold to identify linked upwind states using 
modeling in three prior FIP rulemakings and numerous state-specific 
actions on good neighbor obligations. This continues to be a reasonable 
approach, and indeed courts have repeatedly declined to establish 
bright line criteria for model performance. In upholding the EPA's 
approach to evaluating interstate transport in CSAPR, the D.C. Circuit 
held that it would not ``invalidate EPA's predictions solely because 
there might be discrepancies between those predictions and the real 
world. That possibility is inherent in the enterprise of prediction.'' 
EME Homer City Generation, L.P. v. EPA, 795 F.3d 118, 135 (2015). 
``[T]he fact that a `model does not fit every application perfectly is 
no criticism; a model is meant to simplify reality in order to make it 
tractable.' '' Id. at 135-36 (quoting Chemical Manufacturers 
Association v. EPA, 28 F.3d 1259, 1264 (D.C. Cir. 1994). See also 
Sierra Club v. EPA, 939 F.3d 649, 686-87 (5th Cir. 2019) (upholding 
EPA's modeling in the

[[Page 36717]]

face of complaints regarding an alleged ``margin of error,'' noting 
challengers face a ``considerable burden'' in overcoming a 
``presumption of regularity'' afforded ``the EPA's choice of analytical 
methodology'') (citing BCCA Appeal Grp. v. EPA, 355 F.3d 817, 832 (5th 
Cir. 2003)).
    The Agency will continue to use the CAMx model to evaluate 
contributions from upwind states to downwind areas. The agency has used 
CAMx routinely in previous notice and comment transport rulemakings to 
evaluate contributions relative to the 1 percent threshold for both 
ozone and PM2.5. In fact, in the original CSAPR, the EPA 
found that ``[t]here was wide support from commenters for the use of 
CAMx as an appropriate, state-of-the science air quality tool for use 
in the [Cross-State Air Pollution] Rule. There were no comments that 
suggested that the EPA should use an alternative model for quantifying 
interstate transport.'' 76 FR 48229 (August 8, 2011). In this action, 
the EPA has taken a number of steps based on comments and new 
information to ensure to the greatest extent the accuracy and 
reliability of its modeling projections at Step 1 and 2, as discussed 
elsewhere in this section.
    The EPA disagrees with commenters that case law reviewing changes 
in agency positions such as FCC v. Fox TV Stations, Inc., 556 U.S. 502, 
515 (2009), is applicable with respect to this issue. As explained 
above, under the terms of the August 2018 memorandum, the Agency did 
not conclude that the use of an alternative contribution threshold was 
justified for any states. But even if it were found that the Agency's 
position had changed between this rulemaking action and the August 2018 
memorandum, the FCC v. Fox factors are met. We have explained above 
that there are good reasons for continuing to use a 1 percent of NAAQS 
threshold. We also are aware that we are not using a 1 ppb threshold 
despite acknowledging the potential for doing so in the August 2018 
memorandum. We do not believe that any party has a serious reliance 
interest that would be sufficient to overcome the countervailing public 
interest that is served through the EPA's determination to maintain 
continuity with its longstanding, more protective 1 percent of NAAQS 
threshold in this action. Cf. 88 FR 9373 (reviewing reliance in the 
context of the SIP-disapproval action).
    The EPA therefore will continue its longstanding practice of 
applying the 1 percent of NAAQS threshold in this action.
a. States That Contribute Below the Screening Threshold
    Based on the EPA's modeling and considering measured data at 
violating monitors, the contributions from each of the following states 
to nonattainment or maintenance-only receptors in the 2023 analytic 
year are below the 1 percent of the NAAQS threshold: Colorado, 
Connecticut, the District of Columbia, Delaware, Florida, Georgia, 
Idaho, Maine, Massachusetts, Montana, Nebraska, New Hampshire, North 
Carolina, North Dakota, Rhode Island, South Carolina, South Dakota, 
Vermont, and Washington.\185\ The EPA has already approved these 
states' 2015 ozone good neighbor SIP submittals. 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 final rule. Additionally, 
the EPA has made final determinations that two states outside the 
modeling domain for the air quality modeling analyzed in this final 
rulemaking--Hawaii \186\ and Alaska \187\--do not significantly 
contribute to nonattainment or interfere with maintenance of the NAAQS 
in any other state.
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    \185\ The status of monitoring sites in California to which 
Oregon may be linked is under review. See section IV.G.
    \186\ The EPA approved Hawaii's 2015 ozone transport SIP on 
December 27, 2021. See 86 FR 73129.
    \187\ The EPA approved Alaska's 2015 ozone transport SIP on 
December 18, 2019. See 84 FR 69331.
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    With respect to Wyoming, our methodology when applied using the 
2016v3 modeling suggests that whether the state is linked is uncertain 
and warrants further analysis. The EPA intends to expeditiously review 
its assessment with respect to Wyoming and take action addressing 
Wyoming's good neighbor obligations for the 2015 ozone NAAQS through a 
separate action.
b. States That Contribute at or Above the Screening Threshold
    Based on the maximum downwind contributions in Table IV.F-1, the 
Step 2 analysis identifies that the following 21 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, Oklahoma, Pennsylvania, Texas, Utah, Virginia, 
and West Virginia. Based on the maximum downwind contributions in Table 
IV.F-1, the following 23 states contribute at or above the 0.70 ppb 
threshold to downwind modeling-based maintenance-only receptors in 
2023: Arizona, Arkansas, California, Illinois, Indiana, Iowa, Kentucky, 
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, 
Nevada, New Jersey, New Mexico, New York, Ohio, Oklahoma, Texas, 
Virginia, West Virginia, and Wisconsin. Based on the maximum downwind 
contribution in Table IV.F-3, the following additional states 
contribute at or above the 0.70 ppb threshold to downwind violating 
monitor maintenance-only receptors in 2023: Kansas and Tennessee. 
(However, the EPA is not taking final action based on this analytical 
result for these two states at this time.) The levels of contribution 
between each of these linked upwind states and downwind nonattainment 
receptors and maintenance-only receptors are provided in the Air 
Quality Modeling Final Rule TSD.
    Among the linked states are several western states--California, 
Nevada, and Utah. 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 western state's good 
neighbor SIP submittal that might otherwise be found to contribute 
above 1 percent of the NAAQS without concluding that additional 
emissions reductions are required at Step 3 of the framework.\188\ 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.\189\ The EPA is deferring finalizing a finding at this 
time for Oregon (see section IV.G of this document for additional 
information).
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    \188\ 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.
    \189\ See 81 FR 71991 (October 19, 2016), 82 FR 9155 (February 
3, 2017).
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    As explained in the following section, the EPA is not, in this 
action, altering its prior approval of Oregon's good neighbor SIP 
submission for the 2015 ozone NAAQS. For the remaining western states 
included in this rule, the EPA's modeling supports a conclusion that 
these states are linked above the

[[Page 36718]]

contribution threshold to identified ozone transport receptors in 
downwind 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-only 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 
maintenance under Step 3. The EPA finds that for purposes of this final 
rule, the following 23 states are linked at Step 2 in 2023: Alabama, 
Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New 
York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia, West 
Virginia, and Wisconsin. In addition, the EPA finds that the following 
20 States are linked at Step 2 in 2026: Arkansas, California, Illinois, 
Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, 
Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, 
Texas, Utah, Virginia, and West Virginia. We note that our updated 
modeling for this final rule shows that two states, Minnesota and 
Wisconsin, that we found linked in 2026 at proposal are no longer 
projected to be linked in that year but are linked in 2023.\190\ As at 
proposal, Alabama is only projected to be linked in 2023, not 2026.
---------------------------------------------------------------------------

    \190\ Minnesota and Wisconsin were linked to maintenance-only 
receptors in Cook County, IL in 2023. Minnesota and Wisconsin are 
not linked in 2026 because the 2026 average and maximum design 
values at the monitoring sites are projected to show attainment.
---------------------------------------------------------------------------

    For six states, the EPA's analysis at this time indicates that a 
linkage may exist in 2023 for which the EPA had not proposed FIP 
requirements, or the updated analysis for this final rule suggests that 
linkages we had previously found in the proposed action are now 
uncertain and warrant further analysis. The EPA intends to 
expeditiously address these states in a separate action or actions: 
Arizona, Iowa, Kansas, New Mexico, Tennessee, and Wyoming.

G. Treatment of Certain Monitoring Sites 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 
the EPA's updated modeling used at proposal (2016v2) and again in the 
final modeling (2016v3), Oregon is modeled to contribute above the 1 
percent of NAAQS threshold to several monitoring sites in California 
that would generally meet the EPA's definition of nonattainment or 
maintenance ``receptors'' at Step 1.\191\ At proposal, the EPA 
explained that our analysis of the nature of the air quality problem at 
these monitoring sites led us 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). We explained that we reached this 
conclusion at Step 1 of our 4-step framework.
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    \191\ Monitors are included in the docket for this rulemaking. 
While EPA is providing information about cumulative upwind 
contribution to the California monitors, the Agency is not making a 
determination in this action that these monitors are ozone transport 
receptors.
---------------------------------------------------------------------------

    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.\192\ 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.'' \193\ 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.'' \194\ 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.\195\
---------------------------------------------------------------------------

    \192\ 81 FR 15200 (March 22, 2016) (proposal); 81 FR 31513 (May 
19, 2016) (final rule).
    \193\ 81 FR 15203.
    \194\ Id.
    \195\ Id.
---------------------------------------------------------------------------

    Comment: Commenters criticized what they considered to be unfair 
treatment of Oregon, stating that the EPA is applying a higher 
contribution threshold than it applies to other states. Commenters 
argued that EPA has not established a specific threshold for why the 
level of upwind-state impact at these sites should not be considered 
meaningful. Commenters argued that our analysis ignored the fact that 
there are many monitoring sites in California to which Oregon 
contributes above 1 percent of the NAAQS. Commenters state that EPA has 
failed to explain why Oregon is not subject to this rulemaking, while 
other states contribute lower total downwind ozone contributions and 
fewer receptors. Commenters concluded that since Oregon is linked it 
should be subject to the same emissions control determinations at Step 
3 and 4 as every other state, or otherwise apply the same ``nature of 
the air quality problem'' consideration to eliminate other receptors.
    Response: The EPA acknowledges that several commenters opposed the 
proposed treatment of Oregon and the California monitoring sites to 
which it is linked in the proposed and final modeling. We also 
recognize that other commenters expressed confusion regarding the role 
of this proposed determination at Step 1 and how it relates to the 
longstanding 4-step interstate transport framework that the EPA is 
otherwise applying in this action. In recognition of these concerns and 
the need to give further thought to the appropriate treatment of both 
upwind states and downwind receptors in these circumstances, the EPA is 
deferring finalizing a finding at this time for Oregon. The current 
approval of the state's SIP submission will remain in place for the 
time being, pending further review. We make no final determination in 
this action regarding whether the California monitoring sites at issue 
should or should not be treated as receptors for purposes of addressing 
interstate transport for the 2015 ozone NAAQS.

V. 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 the 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 final rule 
and focuses on the 23 states with FIP requirements identified in the

[[Page 36719]]

previous sections. Following the existing framework as applied in the 
prior CSAPR rulemakings, the 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 
\196\--to evaluate increasing levels of uniform NOX control 
stringency. The multi-factor test, which is central to EPA's Step 3 
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.
---------------------------------------------------------------------------

    \196\ 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 III.A.2 of this document, commenters on the 
proposed rule and previous ozone transport rules have suggested that 
the EPA should regulate VOCs as an ozone precursor. For this final 
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 for nearly all of the linkages 
(121 out of 124 total). Across all receptors, the contribution from 
NOX emissions ranges from 84 percent to 97 percent of the 
total anthropogenic contribution from upwind states. 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 final rule under are 
primarily NOX-limited, rather than VOC-limited. Therefore, 
the EPA continues to find that regulation of VOCs as an ozone precursor 
in upwind states is not necessary to eliminate significant contribution 
or interference with maintenance in downwind areas in this final 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 V.B of this document describes 
the available NOX emissions controls that the EPA evaluated 
for this final rule and their representative cost levels (in 2016$). 
Section V.C of this document discusses EPA's application of that 
information to assess emissions reduction potential of the identified 
control stringencies. Finally, section V.D of this document 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 
whether, based on particularized evidence, its selected control 
strategy would result in over-control for any upwind state 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 V.D of 
this document.
    Finally, while the EPA has evaluated potential emissions reductions 
from non-EGU sources in prior rules and found certain non-EGU emissions 
reductions should inform the budgets established in the NOX 
SIP Call, this is the first action for which the EPA is finalizing non-
EGU emissions reductions within the context of the specific, 4-step 
interstate transport framework established in CSAPR. 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 eliminate ``significant contribution'' while 
avoiding over-control.
    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 inclusive of commenter-provided data. This 
analysis leads the EPA to conclude 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 determines, 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

[[Page 36720]]

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 rulemaking 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 
at the downwind receptors. Section V.B.2 of this document describes 
EPA's process for selecting specific non-EGU industries and emissions 
unit types included in this final rulemaking.
    The EPA notes that its Step 3 analysis for this FIP does not assess 
additional 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 these emissions at the Federal 
level. EPA's various Federal mobile source programs, summarized in this 
section, have delivered and are projected to continue to deliver 
substantial nationwide reductions in both VOCs and NOX 
emissions; these reductions from final rules 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 through such means 
when regulating in place of the states under CAA section 110(c). See 
generally CAA section 209. 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 final 
rulemaking, and the EPA does not evaluate any mobile source control 
measures in its Step 3 evaluation in this rule.\197\ For further 
discussion of EPA's existing and ongoing mobile source measures, see 
section V.B.4 of this document.
---------------------------------------------------------------------------

    \197\ 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 
specific requirements that apply in certain ozone nonattainment 
areas including 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 well as others that meet CAA requirements 
can be effective and appropriate in the context of the planning 
requirements applicable to designated nonattainment areas.
---------------------------------------------------------------------------

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; and (5) installing new SCRs. Finally, for each of these 
combustion and post combustion technologies identified, EPA evaluated 
whether emissions reduction potential from generation shifting at that 
representative dollar per ton level was appropriate at this Step. 
Shifting generation to lower NOX emitting or zero-emitting 
EGUs may occur in response to economic factors. 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. For the reasons explained in the 
following sections and supported by technical information provided in 
the EGU NOX Mitigation Strategies Final Rule TSD included in 
the docket for this final rule, the EPA determined that for the 
regional, multi-state scale of this rulemaking, only EGU NOX 
emissions controls 1 and 3 are possible for the 2023 ozone season 
(fully operating existing SCRs and SNCRs). 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; those controls are 
assumed to be available by the beginning of the 2024 ozone season. All 
cost values discussed in the rest of the section 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.\198\ The EPA 
determined in the Revised CSAPR Update that optimizing SCRs was a 
readily available approach for EGUs to reduce NOX emissions 
in the 12 states addressed by a FIP in that rulemaking. Noticeable 
improvements in emissions rates at units with SCRs during the 2021 and 
2022 compliance period further affirm the ability of sources to quickly 
implement this mitigation strategy and to realize emissions reductions 
from doing so. This emissions reduction measure is currently available 
at EGUs across the broader geography affected in this final rulemaking 
(including in states not previously affected by the Revised CSAPR 
Update). The EPA thus determines that SCR optimization, of both idled 
and partially operating controls, is a viable mitigation strategy for 
the 2023 ozone season.
---------------------------------------------------------------------------

    \198\ 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 Final Rule TSD for this rule 
describes a range of cost estimates for

[[Page 36721]]

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. This cost distinction is 
reflected in the EPA's RIA cost estimates. When representing the cost 
of optimization here, the EPA uses the higher value to reflect both 
optimization of partially operating and idled controls. 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 in 
preparation for this rule, and subsequently evaluated for the final 
rule in 2022 and determined to still be appropriate. The description 
and development of the equations are documented in EGU NOX 
Mitigation Strategies Final Rule TSD and accompanying documents.\199\ 
They are also 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 action.
---------------------------------------------------------------------------

    \199\ 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. Considering the emissions 
data over the full time period from 2009-2019 results in a third-best 
rate of 0.079 pounds NOX per million British thermal units 
(lb/mmBtu). 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 finalizes 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 lb/
mmBtu or lower 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.
    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 end of the 
ozone season control period on September 30. 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.\200\ Therefore, the EPA believes that optimization of existing 
SCRs is possible for the portion of the 2023 ozone season covered under 
this final rule. The recent successful implementation of this strategy 
for the Revised CSAPR Update Rule, and corresponding fast improvement 
in SCR performance rates at units with optimization potential, provides 
further supporting evidence of the viability of this timeframe.
---------------------------------------------------------------------------

    \200\ 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 lb/mmBtu and 2005 
average non-ozone season NOX emissions rates that 
exceeded 0.12 lb/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 23 
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 and 2022 emissions rates. Notably, the higher ozone 
season NOX allowance price observed in 2022 resulted in more 
units operating their controls closer to their potential and bringing 
collective emissions from those 12 states closer to the 2023 emissions 
budgets for those states in this final rule, accordingly.

[[Page 36722]]

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 
Final Rule TSD). For instance, in June of 2021--within months of the 
Revised CSAPR Rule being finalized--Miami Fort Unit 7 and Unit 8 (which 
had substantial SCR optimization potential) were able to reach levels 
of 0.07 lb/mmBtu of NOX (a greater than 50 percent reduction 
from where they had operated the prior year during the same month). 
Such empirical data further illustrates the viability of this 
mitigation strategy for the 2023 control period in response to this 
rule.
    Comment: EPA received comments supporting the 0.08 lb/mmBtu 
emissions rate as achievable and, according to some commenters, 
underestimate the control's potential. Some of these commenters went on 
to provide their own analysis demonstrating that the 0.08 lb/mmBtu was 
achievable not only on average for the non-optimized fleet, but also 
for these individual units and that the resulting state emissions 
budgets were likewise achievable. Some commenters suggested that the 
rate should be lower and premised on EPA using the first- or second-
best year instead of the third best year of SCR performance. Some 
commenters observed that using the same methodology, but omitting SCR 
units that have since retired, could deliver an even lower SCR 
performance benchmark rate.
    Response: The EPA notes that updating the inventory of coal-fired 
EGUs to reflect recent retirements and to include data reported since 
2019 (e.g., 2009-2021) would provide a lower value of 0.071 lb/mmBtu. 
However, EPA acknowledges that 2020 operational data included impacts 
from COVID-19 pandemic shutdowns (such as atypical electricity demand 
patterns) which complicate interpretations of typical EGU emissions 
performance. Additionally, EPA believes that in this context, a unit's 
retirement in 2020 or 2021 does not obviate the usefulness of its prior 
SCR operational data for assessing the emissions control performance of 
other existing SCRs across the fleet. Consequently, EPA is continuing 
to use the same value of the 0.08 lb/mmBtu emissions rate calculated 
from the 2009-2019 data set identified at the time of the final Revised 
CSAPR Update Rule in this rulemaking. EPA's analysis focuses on the 
third best ozone season average rate because EPA believes that the 
first- or second-best rate, consistent with its CSAPR Update final rule 
and in the Revised CSAPR Update, could give undue weight to the 
emissions control performance of new SCRs in their first year of 
service and their corresponding newer SCR components. It does not 
necessarily reflect achievable ongoing NOX emissions rates 
at relatively older SCRs. The third-lowest season was selected because 
it represents a time when the unit was most likely consistently and 
efficiently operating its SCR in a manner representative of sustained 
future operation.
    Comment: Other commenters suggested that EPA should apply a higher 
NOX emissions rate than 0.08 lb/mmBtu to existing SCR at 
coal EGUs premised on considerations such as: a generally reduced 
average capacity factor for coal units in recent years, the age of the 
boiler, coal rank (bituminous or subbituminous), or other unit-specific 
considerations that commenters claim make the 0.08 lb/mmBtu rate 
unattainable for a specific unit.
    Response: EPA did not find sufficient justification to apply a 
higher average emissions rate than 0.08 lb/mmBtu. EPA found that some 
commenters were misunderstanding or misconstruing both EPA's assumption 
and implementation mechanism as a unit-level requirement for every SCR-
controlled unit instead of a reflection of a fleet-wide average based 
on a third-best rate. The commenters' observation--that 0.08 lb/mmBtu 
may be difficult for some units to achieve or may not be a preferred 
compliance strategy for a given unit given its dispatch levels--does 
not contradict EPA's assumption, but rather supports its methodology 
and assumptions. As EPA pointed out in the proposed rule, this fleet-
level emissions rate assumption of 0.08 lb/mmBtu for non-optimized 
units reflects, on average, what those units would achieve when 
optimized. Some of these units may achieve rates that are lower than 
0.08 lb/mmBtu, and some units may operate above that rate based on 
unit-specific configuration and dispatch patterns. In other words, EPA 
is using this assumption as the average performance of a unit that 
optimizes its SCR, recognizing that heterogeneity within the fleet will 
likely lead some units to overperform and others to underperform this 
rate. Moreover, a review of unit-specific historical data indicates 
that this is a reasonable assumption: not only has the group of units 
with SCR optimization potential demonstrated they can perform at or 
better than the 0.08 lb/mmBtu rate on average, over 90 percent of the 
individual units in this group have already met this rate on a seasonal 
and/or monthly basis based on their reported historical data.
    Additionally, EPA's examination of units experiencing SCR 
performance deterioration included notable instances of poor 
NOX control at increased capacity factors. As an example, 
Miami Fort Unit 7 had considerably more hours of operation at a 70 to 
79 percent capacity factor in 2019 compared to previous years. However, 
Miami Fort Unit 7's ozone-season NOX emissions rate 
substantially increased in 2019 compared to previous years. This SCR 
performance deterioration runs counter to the notion that an increase 
in emissions rates is purely driven by reduced capacity factor, as 
suggested by commenters. This substantial deterioration in the median 
emissions rate performance is observable even when comparing specific 
hours in 2019 to specific hours in prior years when the unit operated 
in the same 70 to 79 percent capacity factor range. In fact, in 2019 
the unit experienced notable emissions rate increases from prior years 
across multiple capacity factor ranges as low as 40 percent to as high 
as 80 percent. This type of data indicates instances where the increase 
in emissions rate (and emissions) is not necessitated by load changes 
but is more likely due to the erosion of the existing incentive to 
optimize controls (i.e., the ozone-season NOX allowance 
price has fallen so low that unit operators find it more economic to 
surrender additional allowances instead of continuing to operate 
pollution controls at an optimized level).
    EPA observed this pattern in other units identified in this 
rulemaking as having significant SCR optimization emissions reduction 
potential. In the accompanying Emissions Data TSD for the supplemental 
notice that EPA recently released in a proceeding to

[[Page 36723]]

address a recommendation submitted to EPA by the Ozone Transport 
Commission under CAA section 184(c), EPA noted, ``In their years with 
the lowest average ozone season NOX emissions rates in this 
analysis, these EGUs had relatively low NOX emissions rates 
at mid- and high-operating levels; moreover, there was little 
variability in NOX emissions rates at these operating 
levels. However, during the 2019 ozone season, these EGUs had higher 
NOX emissions rates and greater variability in 
NOX emissions rates across operating levels than in the 
past, particularly at mid-operating levels.'' \201\ That hourly data 
analysis, included in this docket, controls for operating level changes 
and still finds there to be instances across multiple SCR-controlled 
units where hourly emissions rates are increasing even when compared to 
the same load levels in previous years.
---------------------------------------------------------------------------

    \201\ ``Analysis of Ozone Season NOX Emissions Data 
for Coal-Fired EGUs in Four Mid-Atlantic States,'' EPA Clean Air 
Markets Division. December 2020. Available at https://www.epa.gov/sites/production/files/2020-12/documents/184c_emission_data_tsd.pdf.
---------------------------------------------------------------------------

    Some commenters have alleged that in recent years coal-fired EGUs 
have declined in capacity factor and that SCR performance declines at 
those lower operating levels. However, hourly data indicate that 
maintaining consistent SCR performance at lower capacity factors is 
possible. For example, the unit-level performance data in Figure 2 to 
section VI.B of this document show the emissions rate at a coal-fired 
EGU with existing SCR staying relatively low (consistent with our 
optimization assumption of 0.08 lb/mmBtu) and stable across a wide 
range of capacity factors.\202\
---------------------------------------------------------------------------

    \202\ EPA, Air Markets Program Data. Available at www.epa.gov/ampd.
[GRAPHIC] [TIFF OMITTED] TR05JN23.000

    Furthermore, most recent data from 2022 illustrates that cycling 
units do have the ability to adjust cycling patterns in a manner that 
enables them to maintain a lower emissions rate throughout the season 
while still achieving a load cycling pattern at the unit. For example, 
the SCR-controlled Conemaugh Unit 2 in Pennsylvania adjusted operating 
patterns in 2022 to have a slightly higher minimum load in most hours 
(maintaining a range of 550 MW-900 MW for most hours as opposed to 450 
MW-900 MW observed in 2021). This change in minimum load, and 
corresponding minimum operating temperature, enabled the unit to 
maintain emissions rates in the 0.05 lb/mmBtu to 0.10 lb/mmBtu range 
for most of the 2022 season (as opposed to NOX emissions 
rates that regularly exceeded 0.25 lb/mmBtu in the 2021 season). This 
2022 improvement in SCR operation occurred during a period when 
allowance prices increased relative to prior years, creating an 
incentive for potential emissions reductions through SCR optimization.
    Comment: EPA also received comment suggesting it should deviate 
from its approach in the CSAPR Update of using a nationwide data set of 
all SCR controlled coal units to establish a third best year, and 
instead limit the dataset to either just the covered states, or--in the 
case of some commenters--just to the baseline years of those units at 
which EPA is identifying optimization potential. They claim the current 
methodology may capture extremely efficient SCR performance years at 
the best performing units and that level of performance may not be 
available at all units with optimization potential. These commenters 
also disagree with the EPA finding that SCRs can consistently maintain 
a 0.08 lb/mmBtu rate over time.
    Response: EPA reviewed the data and its methodology and evaluated 
it against its intention to identify a technology-specific 
representative emissions rate for SCR optimization. In doing so, EPA 
did not identify any need to make the suggested change. EPA is 
interested in the performance potential of a technology, and a larger 
dataset provides a superior indication of that potential as opposed to 
a smaller, state-limited dataset. Moreover, EPA's use of the third best 
year (as opposed to best) from its baseline period results in an 
average optimization level that is robust

[[Page 36724]]

to the commenters' concern that EPA should not overstate the fleetwide 
representative optimization level. Prior experience with EPA's 
methodology and program has borne out empirical evidence of its 
reasonableness. In both the CSAPR Update and in Revised CSAPR Update 
rule, EPA appropriately relied on the largest dataset possible (i.e., 
nationwide) to derive technology performance averages that it then 
applied respectively to the CSAPR Update 22-state region and the 
Revised CSAPR Update's 12-state region. EPA repeats that successful 
approach in this rule. Finally, as noted in the preceding paragraphs, 
in affirming the reasonableness of this approach, EPA examined the 
historical reported data (pre-2021) for the units in the states with 
SCR optimization potential and found the nationwide derived average 
appropriate and consistent with demonstrated capability and performance 
of units within those states. That is, the vast majority of units to 
which this resulting emissions rate assumption was being applied had 
demonstrated the ability to achieve this rate in some prior year for an 
extended monthly or seasonal basis. This information is discussed 
further in the EGU NOX Mitigation Strategies Final Rule TSD 
in the docket.
    Comment: Some commenters suggested the price of SCR optimization is 
higher than the $1,600 per ton figure proposed due to current market 
conditions for aqueous ammonia or other input prices.
    Response: EPA provides a representative cost for this mitigation 
technology which is anticipated to reflect the cost, on average, 
throughout the compliance period for the rule. While there may be 
volatility in the market during that period where the price falls above 
or below the single representative threshold value, EPA's EGU 
NOX Mitigation Strategies Final Rule TSD explains how the 
representative cost is derived and is inclusive of consultation and 
vetting by third party air pollution control consulting groups. 
Commenters did not demonstrate that observed 2021 elevated prices amid 
market volatility would continue into the future compliance periods 
discussed in this rule. Moreover, the selection of the mitigation 
technology is reflective of a variety of factors including reduction 
potential and air quality impact. A higher cost (commenter suggests up 
to $3,800 per ton) would not change EPA's determination that optimizing 
already existing SCRs is an appropriate mitigation strategy for Step 3 
emissions reduction analysis in this rulemaking as it would remain one 
of the most widely available, widely practiced, and lowest cost 
mitigation measures with meaningful downwind air quality benefit. 
Appendix B of the EGU NOX Mitigation Strategies Final Rule 
TSD further addresses commenters' concerns as it provides a variety of 
sensitivities showing cost per ton levels under a variety of different 
input assumptions (including higher material and reagent cost). It 
supports the continued inclusion of this technology in the rule even in 
the event that higher reagent costs extend into compliance years.
    Comment: While many commenters supported the feasibility of 2023 
ozone-season implementation by noting the ``immediate availability'' of 
SCR optimization, other commenters argued that the engineering, 
procurement, and other steps required for SCR optimization were not 
feasible given the anticipated limited window between rule finalization 
and the start of the 2023 ozone season.
    Response: There is ample evidence of units restoring their optimal 
performance within a two-month timeframe. Not only do units reactivate 
SCR performance level at the start of an ozone-season when tighter 
emissions limits begin, but unit-level data also shows instances where 
sources have demonstrated the ability to quickly alter their emissions 
rate within an ozone-season and even within the same day in some cases. 
Moreover, this emissions control is familiar to sources and was 
analyzed and included in the Revised CSAPR Update emissions budgets 
finalized in 2021 and the CSAPR Update emissions budgets finalized in 
2016. With this experience, and notice through the March 2022 proposed 
rule, as well as over two months from final rule to effective date, the 
viability of this emissions control for the 2023 ozone season is 
consistent with the 2-week to 2-month timeframe that EPA identified as 
reasonable in the CSAPR Update, Revised CSAPR Update, and in this 
rulemaking. Similar to prior rules, commenters provide some unit-level 
examples where it has taken longer. Also similar to those prior rules, 
EPA does not find those unit-level examples compelling in the context 
of its fleet average assumptions and in the implementation context of a 
trading program which provides compliance alternatives in the event a 
specific unit prefers more time to implement a given control measure. 
As noted in Wisconsin, ``. . . all those anecdotes show is that 
installation can drag on when companies are unconstrained by the 
ticking clock of the law.'' 938 F.3d at 330.
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-art combustion control technology. For this rulemaking, 
the Agency re-evaluated its NOX emissions rate assumptions 
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 lb/mmBtu can be 
achieved on average depending on the unit's boiler configuration,\203\ 
and, once installed, reduce NOX emissions at all times of 
EGU operation.
---------------------------------------------------------------------------

    \203\ Details of EPA's assessment of state-of-the-art 
NOX combustion controls are provided in the EGU 
NOX Mitigation Strategies Final Rule TSD.
---------------------------------------------------------------------------

    These assumptions are consistent with the Revised CSAPR Update. 
They are further discussed in the EGU NOX Mitigation 
Strategies Final Rule TSD. In particular, the EPA is finalizing, as 
proposed, the application of the 0.199 lb/mmBtu emissions rate 
assumption for both boiler types (tangentially and wall fired). EPA's 
analysis calculated average emissions rates of 0.199 lb/mmBtu for 
combustion controls on dry bottom wall fired units and 0.146 lb/mmBtu 
for tangentially fired units. However, 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 assignment of a 0.199 lb/mmBtu emissions rate for combustion 
controls at all affected unit types is robust to current and future 
coal choice at a unit.
    The EPA has previously examined the feasibility of installing 
combustion controls and found that industry had demonstrated ability to 
install state-of-

[[Page 36725]]

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).\204\ 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.\205\ Those comments 
provided information on the equipment and typical installation time 
frame for new combustion controls, accounting for all steps. To date, 
EPA has found 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:
---------------------------------------------------------------------------

    \204\ 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.
    \205\ 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 referenced timeframe of approximately 6 to 8 months to 
complete combustion control installation in the region, the EPA is 
finalizing 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 Final 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. 99 percent of units 
have some form of combustion controls, indicating the widespread cost-
effectiveness of this control. See the EGU NOX Mitigation Strategies 
Final Rule TSD for additional details.
    At proposal EPA assumed that emissions reductions from combustion 
control upgrades at affected EGUs in states subject to the Revised 
CSAPR Update program could occur by 2023 given that those EGUs may have 
already begun pursuing such upgrades in response to that previous rule. 
However, EPA does not have data to confirm that presumption, and hence 
EPA is determining in this final rule that combustion control upgrades 
for all affected EGUs, regardless of whether they were previously 
subject to the Revised CSAPR Update program, should be considered 
available by the 2024 ozone season, consistent with the deployment 
schedule noted in this section.
    Comment: Some commenters suggested that EPA, in its modeling for 
the proposed rule, overestimated the ability of combustion control 
technologies to achieve very low NOX emissions rates. The 
commenters claim EPA's assumptions are derived from projected 
NOX emissions rates based on ideal circumstances for 
NOX emissions reductions, including combinations of fuel 
composition and unit design that are not typical and should not be 
extrapolated to the national inventory.
    Response: EPA's emissions performance rate for state-of-the-art 
combustion controls is derived from historical data and takes both 
boiler type and coal choice into account. EPA reviewed historical data 
and identified the average emissions rates for units with this 
technology already in place. It segmented this analysis by boiler type 
(dry-bottom wall-fired boiler and tangentially-fired, and further 
segmented by coal rank to assess the average performance among these 
varying parameters. As explained in the EGU NOX Mitigation Strategies 
Final Rule TSD, EPA chose an emissions rate for which it verified 
accommodated (i.e., was greater than or equal to) the average 
performance rate identified above for each boiler configuration with 
state-of-the-art combustion controls and resulted in reductions 
consistent with the technology's assumed percent reduction potential 
when applied to this subset of units. It also assessed whether the rate 
had been demonstrated by both subbituminous and bituminous coal units 
with state-of-the-art combustion controls. EPA further assessed the 
percent reduction that achieving this rate would require from the 
specific segment of the fleet identified as having this mitigation 
measure available. Here too, EPA found that the effective percent 
reduction for the identified fleet (inclusive of their existing coal 
rank choice) is well within the historical performance range for this 
technology. Therefore, EPA is finalizing the combustion control upgrade 
performance assumption of 0.199 lb/mmBtu as appropriate representative 
average performance rate for this technology and robust to different 
boiler types and coal ranks.
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 22 
linked states with EGU reductions identified in this final rule, 
approximately 11 percent of coal-fired EGU capacity is equipped with 
SNCR.\206\ Recent power sector data suggest that, in some cases, SNCR 
controls have been operating less in 2021 relative to performance in 
prior years. For instance, EPA reviewed the last five years of 
performance data for all the units with SNCR optimization potential in 
its Engineering Analysis. It found that in 2021--the most recent year 
reviewed--that the weighted average ozone season emissions rate for 
these units was higher than the prior three years (indicating some 
deterioration in average performance). Moreover, a unit level review 
illustrated that 80 of the 107 units had performed better in a prior 
year by an average of 13 percent--indicating substantial optimization 
potential.\207\
---------------------------------------------------------------------------

    \206\ https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
    \207\ See ``Historical Emission Rates for Units with SNCR 
Optimization Potential'' in the docket for this rulemaking.
---------------------------------------------------------------------------

    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. 
In this final rule, the EPA is determining that this emissions

[[Page 36726]]

control measure is available beginning in the 2023 ozone season.
    Using the Retrofit Cost Analyzer described in the EGU NOX 
Mitigation Strategies Final 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 finalizes 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.
d. Installing New SNCRs
    The EPA evaluated potential emissions reductions and associated 
costs from retrofitting EGUs with new SNCR post-combustion controls at 
steam units lacking such controls, which can achieve a 25 percent 
NOX reduction on average. 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.\208\ 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 Final Rule TSD, the EPA estimated that $6,700 
per ton reflects a representative SNCR retrofit cost level for these 
units.
---------------------------------------------------------------------------

    \208\ See EGU NOX Mitigation Strategies Final Rule 
TSD for additional discussion.
---------------------------------------------------------------------------

    For this rulemaking, EPA is not considering SNCR installation 
timing unto itself but is instead considering how long eligible EGUs 
may need to adopt either SNCR or SCR as a post-combustion control 
measure. 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. 
However, SNCR retrofits have less pollution reduction potential than 
SCRs, and as explained further in the next section, the EPA is 
identifying the retrofit of new SCR rather than SNCR as a strategy for 
larger steam units due to this lower removal efficiency. This approach 
respects empirical evidence that larger coal-fired EGUs which installed 
post-combustion NOX control technology have overwhelmingly 
chosen SCRs over SNCRs. Even for smaller units less than 100 MW 
identified as potential candidates for SNCR technology, the EPA does 
not want to preclude those units from pursuing SCR in lieu of SNCR.
    Therefore, in this final rule the EPA defines the availability of 
emissions reductions from post-combustion control installation to be in 
2026, the same period as the start of SCR-based reductions becoming 
available, to allow enough time for eligible EGUs to choose between SCR 
or SNCR. SNCR installation shares similar implementation steps with and 
also need to account for the same regional factors as SCR 
installations, which are described in the next section. While the EPA 
is determining that at least 16 months would be needed to complete all 
necessary steps of SNCR development and installation, an eligible EGU 
choosing new SCR instead would require installation timing of 36 to 48 
months. EPA believes its finalized joint timing considerations for 
post-combustion control retrofits (SNCR and SCR) are justified given 
that post-combustion control retrofit decisions are subject to unit-
specific economic and engineering factors and are sensitive to operator 
compliance strategy choices with respect to multiple regulatory 
requirements.
    Comment: Some commenters argued that post-combustion control timing 
assumptions (SCR and SNCR) should be decoupled, which could result in 
the EPA using the 16-month time frame specific to SNCR installation to 
require emissions reductions related to new SNCR installations by the 
2025 ozone season.
    Response: The EPA does not agree that decoupling SCR and SNCR 
timing consideration is justified in the context of this final rule's 
emissions control program for EGUs. Approximately 1,000 tons of 
emissions reduction potential are estimated for the small coal EGUs 
deemed eligible for SNCR retrofit. The incentives provided through the 
implementation of this rule's trading program will encourage these EGUs 
to determine and adopt emissions reduction measures (including SNCR or 
SCR) as soon as possible to reduce their allowance holding compliance 
burden. By scheduling SNCR-related emissions reductions potential for 
the 2026 ozone season, the EPA preserves the opportunity for 
considerably superior emissions reduction potential from these EGUs 
should they select SCR retrofit instead, while still requiring post-
combustion control emissions reduction potential ahead of the next 
attainment date.
    Comment: Some commenters argued that the upper range of SNCR 
NOX removal performance (40 percent) referenced by EPA is 
optimistic for many boilers.
    Response: EPA evaluated both actual performance and engineering 
literature regarding SNCR retrofit technology and found both sources 
supported the range of reduction estimates cited by EPA. (Refer to the 
EGU NOX Mitigation Strategies Final Rule TSD in the docket for this 
rulemaking for additional information.) Moreover, for purposes of 
calculating state budgets, EPA assumes 25 percent reduction from this 
technology--not 40 percent--which reflects a value well within the 
range of documented performance for this technology. Remaining comments 
on SNCR performance potential are addressed in the RTC Document and in 
the EGU NOX Mitigation Strategies Final Rule TSD.
e. Installing New SCRs
    Selective Catalytic Reduction (SCR) controls already exist on over 
66 percent of the coal fleet in the linked states that are subject to a 
FIP in this 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

[[Page 36727]]

rapidly due to a lack of economies of scale.\209\
---------------------------------------------------------------------------

    \209\ 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. Similar to the SNCR retrofits discussed 
in this section, 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. 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). However, since 
that time, the EPA has found up to 36-48 months to be a more 
appropriate installation timeframe for regionwide actions when the EPA 
is evaluating multiple installations at multiple locations.\210\
---------------------------------------------------------------------------

    \210\ See, e.g., CSAPR Close-Out, 83 FR 65878, 65895 (December 
21, 2018) and Revised CSAPR Update, 86 FR 23102 (April 30, 2021). 
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.
---------------------------------------------------------------------------

    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.
    While EPA finds that 36 months is a possible time frame for SCR 
installation at individual units or plants, the total of nearly 31 GW 
of coal capacity with SCR retrofit potential and 19 GW of oil/gas steam 
capacity with SCR retrofit potential within the geographic footprint of 
the final rule is a scale of retrofit activity that is not demonstrated 
to have been achieved within a three-year span based on data from the 
past two decades. 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, EPA is allowing in this final rule 
between 36 to 48 months, consistent with the regional time frame 
discussed for SCR retrofit in prior rules, for the full implementation 
of reductions commensurate with this volume of SCR retrofit capacity, 
as described further in section VI.A of this document.
    The Agency examined the cost for retrofitting a coal unit with new 
SCR technology, which typically attains controlled NOX rates 
of 0.05 lb/mmBtu or less. These updates are further discussed in the 
EGU NOX Mitigation Strategies Final Rule TSD.\211\ Based on 
the characteristics of coal units of 100 MW or greater capacity that do 
not have post-combustion
---------------------------------------------------------------------------

    \211\ 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.
---------------------------------------------------------------------------

    NOX control technology, the EPA estimated a weighted-
average representative SCR cost of $11,000 per ton.\212\
---------------------------------------------------------------------------

    \212\ 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 Final Rule TSD for more 
discussion.
---------------------------------------------------------------------------

    The 0.05 lb/mmBtu emissions 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 emissions rate data for coal-fired units that 
had a relatively recent SCR installation (within the last 10 years). 
The best performing 10 percent of these SCRs were demonstrating 
seasonal emissions 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.\213\ 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 emissions rate for new 
SCR across coal types.
---------------------------------------------------------------------------

    \213\ See ``IPM Model--Updates to Cost and Performance for APC 
Technologies: SCR Cost Development Methodology for Coal-fired 
Boilers''.
---------------------------------------------------------------------------

    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 on a dollar per ton basis. 
Therefore, the EPA identified the portion of the oil/gas steam fleet 
meeting these criteria (i.e., greater than or equal to 100 MW and 
emitting more than 150 tons per ozone season) as representative of the 
SCR retrofit reduction potential.\214\ 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.
---------------------------------------------------------------------------

    \214\ 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.
---------------------------------------------------------------------------

    Comment: Some commenters disagreed with EPA's proposed 36-month 
timeframe for SCR retrofit. These commenters noted that, while possible 
at the unit or plant level, the collective volume of SCR installation 
occurring in

[[Page 36728]]

a limited region of the country would not be possible given the labor 
constraints, supply constraints, and simultaneous outages necessary to 
complete SCR retrofit projects on such a schedule. They noted that 
achieving such a timeframe against a backdrop of such challenging 
circumstances is unprecedented and that EPA's assumptions ignore that 
many of the remaining unretrofitted coal units reflect more site-
specific challenges than those that were already retrofitted on a 
quicker timeframe.
    Response: EPA reviewed the comments and is making several changes 
in this final rule to address some of the concerns identified by the 
commenters. In particular, EPA found that its own review of historical 
retrofit patterns as well as technical information submitted by 
commenters supported commenters' concerns regarding: (1) current and 
anticipated constraints in labor and supply markets, (2) the potential 
collective capacity levels of SCR retrofit within 36 months, and (3) 
possible site-specific complexities at the remaining units without an 
existing SCR. To address these concerns, EPA is phasing in its SCR 
installation requirement over a 48-month time frame in this final rule, 
instead of a 36-month time frame as proposed (see additional detail and 
discussion in section VI.A.2.a and the EGU NOX Mitigation 
Strategies Final Rule TSD). EPA will require half of the reductions 
associated with SCR installation in 2026 and the other half in 2027. 
Additionally, EPA is moving the daily backstop rate for these units 
with identified SCR reduction potential from 2027 to no later than 
2030, which defers the increased allowance surrender ratio for 
emissions above the backstop rate at any outlier units unable to 
complete the retrofit during that time frame. These adjustments 
continue to incentivize reductions in NOX emissions by the 
attainment date that are consistent with cost-effective SCR controls, 
but provide more flexibility (both from timing and technology 
perspective) in how they are procured.
    Some commenters requested more than 48 months to install SCR 
controls based on the collective total volume of SCR retrofit volume 
identified and past projects that took five or more years. EPA 
disagrees with these comments and finds that they ignored key aspects 
of the proposed rule. First, the final rule does not directly require 
implementation of SCR; rather, it requires reductions commensurate with 
SCR installations based on a rigorous assessment of SCR retrofit 
potential. Implementing the reductions through a trading program means 
that sources in many cases, as suggested by the Regulatory Impact 
Analysis (RIA), will find alternative, and more economic means, of 
reducing emissions--including reduced generation and retirements that 
are already planned based on the age of the unit, decarbonization 
goals, or compliance with other Federal/state/local regulation 
compliance dates. Moreover, the additional new generation incentives 
provided by the Inflation Reduction Act (enacted after the proposed 
rule) will further increase the pace of new generation replacing some 
of the older generating capacity identified as having retrofit 
potential.\215\ In short, although EPA identified the total SCR 
retrofit capacity potential for today's existing fleet and does not 
premise any reduction requirements of incremental retirements, the 
announced and planned futures for these units indicates that many will 
likely retire instead of installing SCR. For the capacity identified at 
Step 3 which lacks SCR, the planned or projected retirement in place of 
a retrofit moots the SCR timing for these units. Moreover, it also 
reduces the demand for associated labor and materials which, in turn, 
frees up resources for any units proceeding with a SCR retrofit. 
Therefore, comments which cite labor and supply chain challenges for 
accommodating the entire fleet capacity identified as having SCR 
retrofit potential significantly overstate the supply-side challenge--
as it ignores the fact that much of this capacity has explicit or 
expected operation plans that will result in compliance without a 
retrofit.
---------------------------------------------------------------------------

    \215\ See ``Regulatory Impact Analysis for 2015 Good Neighbor 
Plan, Appendix 4A: Inflation Reduction Act EGU Sensitivity Run 
Results.'' EPA estimated the compliance costs and emissions changes 
of the final rule in the presence of the IRA, but given time and 
resource constraints, did not quantify benefits for this 
sensitivity.
---------------------------------------------------------------------------

    Even for sources choosing a SCR retrofit compliance pathway, many 
of these comments ignore the timing flexibilities of the trading 
program, which (particularly with the changes to the backstop daily 
emissions rate in this final rule) allow sources to temporarily comply 
through means other than SCR retrofit if they experience any site-
specific retrofit limitations that increase their time frame. Also, 
historical examples of SCR retrofit projects that exceeded 48 months in 
duration do not necessarily demonstrate that such projects are 
impossible in less than 48 months, but rather that they can extend 
beyond the timeframe if no requirements or incentives are in place for 
a faster installation. Some also cite site-specific conditions that 
resulted an outlier cases of project timing that would not be 
representative of the conditions expected at future retrofit 
projects.\216\
---------------------------------------------------------------------------

    \216\ Commenters, for example, cited the timing of SCR 
installation at Sammis 6 and 7. Here, the SCR design and material 
delivery schedule were tailored to meet unique site conditions that 
were unlike many other SCR systems where large modules can be used 
to maximize shop and ground assembly techniques. Additional 
information is available at https://www.babcock.com/home/about/resources/success-stories/sammis-plant.
---------------------------------------------------------------------------

    Comment: Some stakeholders suggested that EPA's cost estimates of 
$11,000 per ton are premised on a 15-year book life of the equipment 
and are therefore too optimistic for units that plan to retire in well 
under 15 years.
    Response: EPA analysis of SCR retrofit cost reflects a 
representative value for the technology based on a weighted average 
cost. The underlying data and the discussion in the EGU NOX 
Mitigation Strategies Final TSD illustrates that these costs can vary 
significantly at the unit level based on factors such as the length of 
time a pollution control technology would be in operation, the capacity 
factor of the unit (i.e., how much does it operate), its size or 
potential to emit, and its baseline emissions rate. The EPA has not in 
prior transport rulemakings used such factors as justification to 
excuse any source that is significantly contributing to nonattainment 
or interfering with maintenance in another state from eliminating that 
significant contribution as expeditiously as practicable. Unlike under 
other statutory provisions that may require retrofit of emissions 
controls on existing sources, such as under CAA section 111(d) or CAA 
section 169A, there is no remaining useful life factor expressly 
identified as a justification to relax the requirements of CAA section 
110(a)(2)(D)(i)(I). EPA continues to believe that where an emissions 
control strategy has been identified at Step 3 that is cost-effective 
on a regional scale and provides meaningful downwind air quality 
improvement, and is thus appropriately identified as necessary to 
eliminate significant contribution under the good neighbor provision, 
it would not be appropriate to allow emissions to continue in excess of 
those achievable emissions reductions beyond the timeframe for 
expeditious implementation of reductions as provided under the larger 
title I structure of the Act for attaining and maintaining the NAAQS. 
The court in Wisconsin recognized that where such emissions have been 
identified, they should be eliminated as expeditiously as practicable, 
and in line with the

[[Page 36729]]

attainment schedule for downwind areas, which, for the 2015 ozone 
NAAQS, is provided in CAA section 181. 938 F.3d at 313-20.
    Further, EPA observes that more than one-third of the identified 
SCR retrofit potential (in terms of generating capacity) has no planned 
retirement date within 15 years, and therefore the cost of pollution 
control technology on such units would likely be lower, holding all 
other parameters equal, on a dollar per ton basis by virtue of the 
length of time the pollution control equipment may be in operation. Nor 
does EPA agree that units that would retire in less than 15 years 
should automatically be considered to face an unreasonably higher cost 
burden. Based on data analyzed in the EGU NOX Mitigation 
Strategies Final Rule TSD, we find that the cost per ton associated 
with SCR retrofit technology does not begin to increase significantly 
above the $11,000/ton benchmark unless units have dramatically lower 
operating capacity or retire in less than 5 years' time--as illustrated 
in Figure 1 to section V.B.1.e of this document.
[GRAPHIC] [TIFF OMITTED] TR05JN23.001

    Finally, EPA's identification of this mitigation strategy is not 
meant to be limited only to units that experience a retrofit cost that 
is less than the representative cost threshold. First, that threshold 
represents an average, meaning that EPA's analysis already recognizes 
that some units on a facility-specific basis may face costs higher than 
that threshold. Further, EPA identifies this technology as widely 
available, implemented in practice already at many existing EGUs, and 
now standard for any coal-fired unit coming online in the past 25 
years. More than 66 percent of the current large coal fleet already has 
such controls in place. Even if the cost were higher for some units for 
the reasons provided by commenters--and there were no less costly means 
provided to them to achieve the same level of emissions reduction 
(which the trading program allows for)--that would not necessarily 
obviate EPA's basis for finding that an emissions-reduction requirement 
commensurate with this standard pollution control practice for this 
unit type is warranted. The implementation of emissions reductions 
through a trading program, and its corresponding compliance 
flexibilities, make the use of a single representative cost all the 
more appropriate in this assessment. Therefore, upon reviewing all of 
the data including the information supplied by commenters, and even 
accounting for certain units' announced plans to retire earlier than an 
assumed 15-year book life for SCR retrofit technology, EPA finds its 
representative cost for this technology to be appropriate and 
reasonable for purposes of analysis under CAA section 
110(a)(2)(D)(i)(I) and maintains this cost estimate in the final rule.
---------------------------------------------------------------------------

    \217\ ``Debt Life'' refers to the term length, or duration, for 
a loan used to finance the retrofit.
---------------------------------------------------------------------------

    However, in recognition of the unique circumstances related to the 
transition of the power sector away from coal-fired and other high-
NOX emitting fuels and generating technologies, which is 
anticipated to accelerate in the late 2020s and into the 2030s, EPA has 
adjusted the final rule to avoid imposing a capital-intensive control 
technology retrofit obligation which could have overall net-negative 
environmental consequences (e.g., by extending the life of a higher-
emitting EGU or necessitating the allocation of material and personnel 
that could be used for more advanced clean-technology

[[Page 36730]]

innovations). For units that plan to retire by 2030, the final rule--by 
extending the daily backstop rate to 2030--allows these units to 
continue to operate, so long as they comply with the mass-based 
emissions trading program requirements.\218\ Therefore, a unit 
experiencing a higher dollar per ton retrofit cost due to retirement 
plans has the flexibility to install less capital intensive controls 
such as SNCR, procure less costly allowances through either banking or 
purchase, or they may also reduce their allowance holding requirement 
through reduced utilization consistent with their phasing out towards a 
planned retirement date. This flexibility that EPA has included in the 
final rule is discussed in further detail in section VI.B of this 
document.
---------------------------------------------------------------------------

    \218\ In the RIA, EPA has modeled the mass-based budgets that 
are premised on retrofit of SCR technology with the option of 
complying through other strategies, and finds that they are readily 
achievable through those other strategies.
---------------------------------------------------------------------------

    Comment: Some commenters suggested that the 0.05 lb/mmBtu emissions 
rate assumed for new SCRs at large coal units is not achievable at all 
coal units with retrofit potential and that EPA should raise this 
performance assumption to a value of 0.08 lb/mmBtu consistent with that 
assumption for existing SCRs.
    Response: First, EPA believes the commenter misunderstands its 
intention with the 0.05 lb/mmBtu SCR rate assumption. This is meant to 
reflect a representative assumption for emissions rate performance for 
new SCR installed on the currently unretrofitted coal fleet--in this 
respect, it represents an average, not a maximum. EPA recognizes that 
some units will likely perform better (i.e., lower) than this rate and 
some will potentially perform worse (i.e., higher) than this rate--but 
that 0.05 lb/mmBtu is a reasonable representation of new SCR retrofit 
potential on a fleet-wide basis and for identifying expected state and 
regional emissions reduction potential from this technology. It would 
be inappropriate for EPA to use the worst performing tier of new SCR 
retrofit for this representative value. Moreover, EPA's review of 
historical environmental performance for recently installed SCRs does 
not support any indication that 0.05 is not representative of the 
retrofit potential for the fleet. EPA found that three quarters of the 
SCR retrofit projects completed in the last 15 years have achieved a 
rate of 0.05 lb/mmBtu or better on a monthly or seasonal basis. 
Moreover, its review of the engineering literature and consultation 
with third party pollution control engineering consultancies suggests 
that vendors are often willing to guarantee 0.05 lb/mmBtu seasonal 
performance for new SCR retrofit projects. Current SCR catalyst 
suppliers provide NOX emissions warranties based at the 
catalyst's end-of-life period, often after 16,000 to 24,000 hours of 
operations, with newer catalyst achieving similar or better 
NOX removal rates. Standard commercial terms, made by the 
purchaser to the SCR Retrofit supplier, can specify a system capable of 
meeting the proposed NOX emissions rate and define the 
catalyst operational life before replacement. Thus, achieving the 
proposed reduction rates is accomplished through the buyer specifying 
the SCR retrofit requirements and the supplier providing an optimized 
system design and installing sufficient catalyst for the targeted end-
of-life NOX emissions rate. The agency is confident that SCR 
retrofit suppliers will be able to warrant their offerings for the 
emissions rates proposed in the regulation and to provide sufficient 
operating life for the affected sector.
    Comment: Some commenters suggest that the evaluation of pollution 
control installation cost at Step 3 should be segmented depending on 
unit characteristics, and by failing to do so understate the cost of 
retrofitting SCR controls. In particular, these commenters note that 
units with lower capacity factors, different coal ranks, with pre-
existing controls--such as SNCR--face substantially higher dollar per 
ton reduced costs than those that do not have such controls in place 
and should not be identified as a cost-effective mitigation strategy.
    Response: Consistent with prior CSAPR rulemakings, at Step 3 EPA 
evaluates a mitigation technology and its representative cost and 
performance for the fleet on average. This representative cost is 
inclusive and robust to the portion of the fleet that may face higher 
dollar per ton cost. Both the ``Technical Support Document (TSD) for 
the Proposed Federal Implementation Plan Addressing Regional Ozone 
Transport for the 2015 Ozone National Ambient Air Quality Standard, 
Docket ID No. EPA-HQ-OAR-2021-0668, EGU NOX Mitigation 
Strategies Proposed Rule TSD'' (Feb. 2022), hereinafter referred to as 
the EGU NOX Mitigation Strategies Proposed Rule TSD, and the 
EGU NOX Mitigation Strategies Final TSD discuss the SCR 
retrofit cost specific to the segment of the fleet that has a SNCR in 
place and notes that those unit-level higher retrofit cost estimates 
are factored into its determination of the fleet-wide representative 
number. Although EPA believes its representative cost are appropriate 
and underpinned by operating assumptions reflective of the fleet 
averages, it nevertheless examined how cost would vary based on some of 
the variables highlighted by commenter. The EPA derived its capacity 
factor assumption based on expected future operations of this fleet 
segment that are inclusive of units operating at a range of capacity 
factors. It also examined how cost would change assuming different coal 
rank, assuming different book life, and different reagent cost. These 
analyses are discussed and shown in Appendix B of the EGU 
NOX Mitigations Strategies Final Rule TSD and demonstrate 
that even under different operating assumptions, the variation in cost 
does not reach a point that would reverse EPA's finding regarding the 
appropriateness of this technology as part of this final rule's control 
stringency. Moreover, as discussed in section V.D of this document, EPA 
identifies appropriate mitigation strategies based on multiple 
factors--not solely on cost, and there is no indication that an 
individual unit's higher retrofit cost would obviate the 
appropriateness of retrofitting this standard and best practice 
technology at the unit. Finally, in prior rules and in the proposal, 
EPA recognized that some units will have higher cost and some will have 
lower cost relative the fleetwide representative value provided. 
Implementing the region and state reduction requirements through a 
mass-based trading program provides a means of alternative lower cost 
compliance for those sources particularly concerned about the higher 
retrofit cost at their unit.
    Comment: Some commenters suggested that EPA's proposed 
representative cost for SCR pollution control is likely too high and 
overstates the true cost of such control. They also noted it aligns 
with agency precedent. These commenters claim that EPA's cost recovery 
factor is higher than necessary (thus inflating the cost) as it 
reflects a weighting of utility-owned to merchant-owned plants that is 
representative of the fleet, but not the unretrofitted fleet with this 
retrofit potential identified in this rule. They also noted that EPA's 
assumed interest rate informing the cost estimate was higher than the 
prime rate in June of 2022.
    Response: EPA agrees that its approach for identifying 
representative cost thresholds is aligned with prior rules and agrees 
that its approach is reasonable. As the commenter points out, prime 
rates and cost recovery factors may indeed be lower in recent data than 
those assumed by EPA for future years. However, given the

[[Page 36731]]

volatility among these metrics, EPA believes its choices are 
appropriate to build cost estimates that are robust to future 
uncertainty, and if these cost input factors do materialize to be the 
lower values highlighted by commenter, then it will result in a lower 
cost assumed in this final rule, but would not otherwise alter any of 
the stringency identification or regulatory findings put forward in 
this final rule. EPA performed a cost sensitivity analysis in Appendix 
B of the EGU NOX Mitigation Strategies Final Rule TSD which 
shows how cost for this technology would vary based on different 
assumed levels for this variable. This analysis shows that under lower 
interest rates such as those put forward by commenter, that technology 
cost would drop by approximately 15 percent relative to the 
representative values put forward in this rule.
f. Generation Shifting
    At proposal, EPA considered intrastate emissions reduction 
potential from generation shifting across the representative dollar per 
ton levels estimated for the emissions controls considered in previous 
sections. 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.
    The EPA recognizes that imposing a NOX-control 
requirement on affected EGUs, like any environmental regulation, 
internalizes the cost of their pollution, which could result in 
generation shifting away from those sources toward other generators 
offering electricity at a lower pollution cost. If, in the context of a 
market-based allowance trading program form of implementation, the EPA 
imposes a preset emissions budget that is premised only on assumed 
installation, optimization, and continued operation of unit-specific 
pollution control technologies, with no accounting for the likely 
generation shift in the marketplace away from these higher-polluting 
sources, that preset emissions budget will contain more tons than would 
be emitted if the affected EGUs achieved the emissions performance 
level (on a rate basis) selected at step 3. Hence, EPA has previously 
quantified and required expected emissions reductions from generation 
shifting in prior transport rules to avoid undermining the program's 
incentive to install, optimize, and operate controls identified in the 
Agency's determinations regarding the requisite level of emissions 
control at Step 3. See, e.g., 81 FR 74544-45; 76 FR 48280.
    As in these prior rules, at proposal, the EPA did not identify 
generation shifting as a primary mitigation strategy and stringency 
measure on its own, but included emissions reductions from this 
strategy as it would be projected to occur in response to the selected 
emissions control stringency levels (and corresponding allowance price 
signals in step 4 implementation). For this rule's proposal, the EPA 
only specified emissions reductions from generation shifting in its 
preset budget calculations for 2023 and 2024. Because this rule's 
dynamic budget methodology applies the selected control stringency's 
emissions rates to the most recently reported heat input at each 
affected EGU, dynamic budgeting effectively serves a similar purpose to 
our ex ante quantification of emissions reduction potential from 
generation shifting for preset budgets in prior transport rules, i.e., 
to adequately and continuously incentivize the implementation of the 
emissions control strategies selected at Step 3. Therefore, dynamic 
budgets under this rule's program moot the need to specify discrete 
emissions reduction potential from generation shifting for those 
control periods, as they automatically reflect whatever generation 
balance affected EGUs would determine in the marketplace inclusive of 
their response to the emissions performance levels imposed by this 
rule.
    Comment: Commenters offered both support for and opposition against 
the inclusion of generation shifting at Step 3 analysis for EGUs. Those 
in support noted that inclusion of emissions reductions from 
generation-shifting is integral to the successful implementation of the 
pollution control measures identified in the selected control 
stringency at Step 3. Those opposed generally argued the EPA was 
overestimating reduction potential from generation shifting in light of 
recent volatility and high prices in the markets for lower emitting 
fuels such as natural gas. Commenters also noted the electrical grid in 
certain regions has constraints that would make generation shifting 
more difficult than the EPA assumed. Commenters also asserted that the 
EPA did not have the legal authority to require generation shifting.
    Response: The EPA disagrees with these comments regarding our legal 
authority but notes this issue is not relevant for purposes of this 
final action. The EPA continues to believe it has authority under CAA 
section 110(a)(2)(D)(i)(I) to consider and require emissions reductions 
from generation shifting if the EPA were to find that strategy was 
necessary to eliminate significant contribution. However, based on 
circumstances currently facing affected EGUs, as well as the inherent 
strength of the dynamic budget methodology to automatically reflect the 
market-determined balance of generation across sources responding to 
this rule, the EPA is not specifying emissions reduction potential from 
generation shifting as a part of the Step 3 analysis, nor to require 
any emissions reductions from generation shifting in preset budgets 
formulated under Step 4 for any control period, for this final rule.
    Currently observable market conditions (e.g., fuel prices) present 
unusual uncertainty with respect to key economic drivers of generation 
shifting. The availability of emissions reductions through generation 
shifting, and the magnitude of those emissions, is dependent on the 
availability and cost of substitute generation. The primary driver of 
near-term generation shifting-based emissions reductions has been 
shifting to lower-emitting natural gas generation. Recent volatility 
and high prices in the natural gas market have increased the 
uncertainty and reduced the potential of this emissions control 
strategy at any given cost threshold in the near term. For example, 
Henry Hub natural gas prices went from under $3.00/mmBtu during most of 
the last decade to an average of nearly $8.00/mmBtu for the most recent 
(2022) ozone season before declining sharply at the start of 2023. The 
current volatility in natural gas prices reduces the availability of 
emissions reductions from generation shifting and make its 
identification and quantification too uncertain for incorporation into 
Step 3 emissions reduction estimates for this rulemaking.
    The Step 4 dynamic budget-setting process of this rule obviates the 
need to specify and require discrete emissions reductions from 
generation shifting under Step 3. As discussed in section VI of this 
document, the EPA in this final rule will implement a budget-setting 
approach that relies on two components: first, we have calculated 
``preset'' budgets that reflect the best information currently 
available about fleet change over the period 2023 through 2029. Second, 
beginning in 2026, dynamic state emissions budgets will be calculated 
that will reflect the balance of generation across sources reported to 
EPA by EGU operators. Between 2026 and 2029, the actual budget that 
will be implemented will

[[Page 36732]]

reflect the greater of either the preset budget or the dynamic budget 
calculation; from 2030 onwards, the budgets will be set only through 
the dynamic budget calculation. This overall approach is well suited 
for a period of significant power sector transition driven by a variety 
of economic, policy, and regulatory forces and allows for the balance 
of generation in this period to adjust in response to these forces 
while nonetheless ensuring that the budgets will continuously 
incentivize the emissions control stringency identified at Step 3. See 
section VI.B.4 of this document for further discussion on the 
interaction of preset and dynamic budgets during the 2026-2029 time 
period. With these approaches, and on the present record before the 
Agency, we conclude that the estimation and incorporation of specified 
emissions reductions from generation shifting at Step 3 is not 
necessary to eliminate significant contribution from EGUs for the 2015 
ozone NAAQS through this rule's program implementation.
    In previous CSAPR rulemakings, the EPA included generation shifting 
in the budget setting process to capture those reductions that would 
occur through shifting generation as an economic response to the 
control stringency determined based on the selected NOX 
control strategies. See, e.g., 81 FR 74544-45. ``Because we have 
identified discrete cost thresholds resulting from the full 
implementation of particular types of emissions controls, it is 
reasonable to simultaneously quantify the reduction potential from 
generation shifting strategy at each cost level. Including these 
reductions is important, ensuring that other cost-effective reductions 
(e.g., fully operating controls) can be expected to occur.'' EGU 
NOX Mitigation Strategies Final Rule TSD (EPA-HQ-OAR-2015-
0500-0554), at 11-12.
    Commenters on this rule and prior transport rules have observed 
that using preset budgets to factor in generation shifting is flawed in 
that it results in EPA incorporating specific quantities of emissions 
reductions from discrete levels of generation shifting that are 
projected to occur but may in fact ultimately transpire differently in 
the marketplace. Commenters on this rule claim that other variables, 
such as constraints in transmission capacity or changes in fuel prices, 
can drive such differences in projected versus realized generation 
shifting, and these concerns are particularly exacerbated in a time of 
significant uncertainty around energy supplies and markets together 
with new laws passed by Congress (e.g., the Infrastructure Investment 
and Jobs Act and the Inflation Reduction Act) driving the current 
transformation of the power sector. By refraining in this rule from 
specifying discrete emissions reductions from generation shifting in 
preset budgets and instead relying on a dynamic budgeting approach to 
reflect market-driven generation patterns, EPA ensures that its budgets 
remain sufficiently stringent over the long term to continually 
incentivize the emissions control stringency it determined to be cost-
effective and therefore appropriate to eliminate significant 
contribution at Step 3. Thus, dynamic budgeting addresses the same 
concern that animated our use of generation shifting in the CSAPR 
rulemakings, but in doing so uses a market-following approach that will 
accommodate, over the long term, unforeseen drops or increases in heat 
input levels.
g. Other EGU Mitigation Measures
    The EPA requested 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 and Final Rule TSDs discussed 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).
    Comment: Some commenters emphasized that simple cycle combustion 
turbines play a significant role in downwind contribution, and they 
highlight that states such as New York have imposed emissions limits on 
these sources acknowledging their impact on downwind nonattainment. 
These commenters suggest that EPA pursue and expedite the 
implementation of these or similar mitigation measures.
    Response: As explained in greater detail in the EGU NOX 
Mitigation Strategies Final TSD, both the configuration and operation 
of this segment of the EGU fleet reflects significant variability among 
units and across time. In other words, one unit may have a capacity 
factor in a given year that is one hundred times greater than a similar 
unit in that same year, or even than its own capacity factor from a 
preceding year. This type of variability and heterogeneity make it 
unlikely that there is a single cost-effective control strategy across 
this fleet segment, and commenters did not provide evidence to the 
contrary. EPA's analysis discussed in the EGU NOX Mitigation 
Strategies Final 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). EPA analysis estimates a representative cost of $22,000 per ton 
for dry low NOX burners or ultra-low NOX burners 
at these simple cycle combustion turbines, and over $100,000 per ton 
for SCR retrofit at some combustion turbines. Therefore, EPA does not 
identify any such uniform mitigation measure at Step 3 when estimating 
reduction potential.
    Nonetheless, the EPA recognizes that these simple cycle combustion 
turbines may have cost-effective emissions-reduction opportunities. 
These units are included in the emissions trading program and 
therefore, as in prior transport rules, the program continues to 
subject them to an allowance holding requirement under this rule which 
will likely incentivize any available cost-effective NOX 
reductions from these EGUs. For instance, emissions rates from these 
units in New York were considerably lower in 2022, when they faced a 
high allowance price, versus 2021, when the allowance price was much 
lower. Therefore, we find that the appropriate treatment of these units 
in this final rule is to continue to include them in the emissions 
trading program to incentivize cost-effective emissions reductions, but 
EPA does not find the magnitude or consistency of cost-effective 
mitigation potential to establish a specific increment of emissions 
reduction through a specific Step 3 emissions control determination. 
Moreover, while EPA's program will incentivize any available cost-
effective reductions within this cadre of units (and such behavior is 
captured in its final program evaluation and modeling the RIA), it does 
not obviate the need for the other EGU cost-effective reductions 
elsewhere as suggested by some commenters.
2. Non-EGU or Stationary Industrial Source NOX Mitigation 
Strategies
    In the early stages of preparing the proposed FIP, the EPA 
evaluated air quality modeling information, annual emissions, and 
information about potential controls to determine which industries, 
beyond the power sector, could have the greatest impact on downwind 
receptors' air quality and therefore the greatest impact in providing 
ozone air quality improvements in affected downwind states through 
reducing those emissions. Specifically, the EPA conducted a screening 
assessment focused on individual emissions units with >100

[[Page 36733]]

tpy of actual NOX emissions in 23 upwind states. Once the 
industries were identified, the EPA used its Control Strategy Tool to 
identify potential emissions units and control measures and to estimate 
emissions reductions and compliance costs associated with application 
of non-EGU emissions control measures. The technical memorandum 
``Screening Assessment of Potential Emissions Reductions, Air Quality 
Impacts, and Costs from Non-EGU Emissions Units for 2026'' (``Non-EGU 
Screening Assessment'' or ``screening assessment'') lays out the 
analytical framework and data used to prepare proxy estimates for 2026 
of potentially affected non-EGU facilities and emissions units, 
emissions reductions, and costs.\219\
---------------------------------------------------------------------------

    \219\ The memorandum is available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0150.
---------------------------------------------------------------------------

    This screening assessment was not intended to identify the specific 
emissions units subject to the proposed emissions limits for non-EGU 
sources but was intended to inform the development of the proposed rule 
by identifying proxies for (1) non-EGU emissions units that potentially 
had the most impact in terms of the magnitude of emissions and 
potential for emissions reductions, (2) potential controls for and 
emissions reductions from these emissions units, and (3) control costs 
from the potential controls on these emissions units. This information 
helped shape the proposed rule.
    To further evaluate the industries and emissions unit types 
identified by the screening assessment and to establish the 
applicability criteria and proposed emissions limits, the EPA reviewed 
RACT rules, NSPS rules, NESHAP rules, existing technical studies, rules 
in approved SIP submittals, consent decrees, and permit limits. That 
evaluation is detailed in the Proposed Non-EGU Sectors TSD prepared for 
the proposed FIP.\220\
---------------------------------------------------------------------------

    \220\ The TSD for the proposed FIP is available in the docket 
here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0145.
---------------------------------------------------------------------------

    In this final rule, for purposes of this part of the Step 3 
analysis, the EPA is retaining emissions control requirements for these 
industries and many of the emissions unit types included in the 
proposal. However, based on comments that credibly indicated in certain 
cases that emissions reduction opportunities are either not available 
for certain unit types or are at costs that are far greater than the 
EPA estimated at proposal, the EPA has changed the final rule to either 
remove or adjust the applicability criteria for such units. For a 
detailed discussion of the changes between the proposed FIP and this 
final rule, in emissions unit types included and in emissions limits, 
see section VI.C of this document. Tables I.B-2 through I.B-7 in 
section I.B of this document identify the emissions units and 
applicable emissions limitations, and Table II.A-1 in section II.A of 
this document identifies the industries included in the final rule.
    For the final rule, to determine NOX emissions reduction 
potential for the non-EGU industries and emissions unit types, with the 
exception of Solid Waste Combustors and Incinerators, we used a 2019 
inventory prepared from the emissions inventory system (EIS) to 
estimate a list of emissions units captured by the applicability 
criteria for the final rule. For Solid Waste Combustors and 
Incinerators, the EPA estimated the list of covered units using the 
2019 inventory, as well as the NEEDS-v6-summer-2021-reference-case 
workbook.\221\ Based on the review of RACT, NSPS, NESHAP rules, as well 
as SIPs, consent decrees, and permits, we also assumed certain control 
technologies could meet the final emissions limits.\222\ We did not run 
the Control Strategy Tool to estimate emissions reductions and costs 
and instead programmed the assessment using R.\223\ Using the list of 
emissions units estimated to be captured by the final rule 
applicability criteria, the assumed control technologies that would 
meet the emissions limits, and information on control efficiencies and 
default cost/ton values from the control measures database (CMDB),\224\ 
the EPA estimated NOX emissions reductions and costs for the 
year 2026. We estimated emissions reductions using the actual emissions 
from the 2019 emissions inventory. In the assessment, we matched 
emissions units by Source Classification Code (SCC) from the inventory 
to the applicable control technologies in the CMDB. We modified SCC 
codes as necessary to match control technologies to inventory records.
---------------------------------------------------------------------------

    \221\ The workbook is available here: https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.
    \222\ The Final Non-EGU Sectors TSD is available in the docket.
    \223\ R is a free software environment for statistical computing 
and graphics. Additional information is available here: https://www.r-project.org/.
    \224\ More information about the Control Strategy Tool (CoST) 
and the control measures database (CMDB) can be found at the 
following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
---------------------------------------------------------------------------

    The EPA recognized both at proposal and in the final rule that the 
cost per ton of emissions controls could vary by industry and by 
facility. The $7,500 marginal cost/ton threshold reflected in the Non-
EGU Screening Assessment functioned as a relative, representative cost/
ton level. Similar to the role of cost-effectiveness thresholds the EPA 
uses at Step 3 to evaluate EGU emissions control opportunities, this 
threshold is not intended to represent the maximum cost any facility 
may need to expend but is rather intended to be a representative figure 
for evaluating technologies to allow for a relative comparison between 
different levels of control stringency. The value was used to identify 
potentially cost-effective controls for further evaluation.
    In the final rule, partly in recognition of the many comments 
indicating widely varying cost-per-ton values across industries and 
facilities, the EPA has updated its analysis of costs for the covered 
non-EGU industries. This data is summarized in the Technical Memorandum 
``Summary of Final Rule Applicability Criteria and Emissions Limits for 
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the 
Final Emissions Limits, and Estimated Emissions Units, Emissions 
Reductions, and Costs,'' available in the docket. We further respond to 
comments on the screening assessment in section 2.2 of the response to 
comments document.
3. Other Stationary Sources NOX Mitigation Strategies
    As part of its analysis for this final 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) solid waste incineration units, 
(2) electric generating units less than or equal to 25 MW, and (3) 
cogeneration units. EPA's initial assessment did not lead it to propose 
inclusion of the units in these categories. However, EPA requested 
comment on whether any particular units within this category may offer 
cost-effective reduction potential.
    Based on our request for comment, comments received, and our 
further evaluation, the EPA is including emissions limits and 
associated control requirements for the ozone season for solid waste 
incinerator units in this final rule, in line with the requirements we 
laid out for comment at proposal. Our analysis in this final rule 
confirms that these units have emissions reductions of a magnitude, 
degree of beneficial impact, and cost-effectiveness that is on par with 
the units in other industrial sectors included in this final rule.

[[Page 36734]]

    For electric generating units less than 25 MW and cogeneration 
units previously exempted from EGU emissions budgets established 
through ozone interstate transport rules, the EPA has determined that 
these units should not be treated as EGUs in this final rule.
    The EPA provides a summary of these three segments, their emissions 
control opportunities, and potential air quality benefits in the 
following sections. Additional considerations are further discussed in 
the EGU NOX Mitigation Strategies Final TSD and in the RTC 
Document.
a. Municipal Solid Waste Units
    At proposal, the EPA solicited comments on whether NOX 
emissions reductions should be sought from municipal waste combustors 
(MWCs) to address interstate ozone transport, specifically on potential 
emissions limits, control technologies, and control costs. The EPA 
requested comment on emissions limits of 105 ppmvd on a 30-day rolling 
average and a 110 ppmvd on a 24-hour block average based on 
determinations made in the June 2021 Ozone Transport Commission (OTC) 
Municipal Waste Combustor Workgroup Report (OTC MWC Report). See 87 FR 
20085-20086. The OTC MWC Report found that MWCs in the Ozone Transport 
Region (OTR) are a significant source of NOX emissions and 
that significant annual NOX reductions could be achieved 
from MWCs in the OTR using several different technologies, or 
combination of technologies at a reasonable cost. The OTC MWC report is 
included in the docket for this action.
    Comment: The EPA received multiple comments supporting the 
inclusion of emissions limits for MWCs in the final rule. Commenters 
noted that MWCs are significant sources of NOX that 
contribute to ozone problems in the states covered by the proposal. 
Multiple commenters referenced the OTC MWC report to contend that 
NOX emissions from MWCs could be significantly reduced at a 
reasonable cost. Some commenters reasoned that sources closer to 
downwind monitors, including MWCs, should be regulated as a more 
targeted approach and a means to prevent overcontrol of upwind sources. 
Commenters also noted that the OTC recently signed a memorandum of 
understanding (MOU) requesting that OTC member states develop cost 
effective solutions and select the strategy or combination of 
strategies, as necessary and appropriate, that provides both the 
maximum certainty and flexibility for that state and its MWCs. 
Additionally, multiple commenters noted that MWCs are often located in 
economically marginalized communities or communities of color. Lastly, 
one commenter stated that MWCs were arbitrarily excluded from the non-
EGU screening assessment prepared for the proposal.
    Response: As described in section VI.B.2 of the notice of proposed 
rulemaking, the EPA assessed emissions reduction potential from non-
EGUs by preparing a screening assessment to identify those industries 
that could have the greatest air quality impact at downwind receptors. 
While the EPA did not prepare an updated non-EGU screening assessment 
in preparation for this final rule, the Agency did evaluate MWCs using 
the criteria developed in the screening assessment for proposal and 
determined that MWCs should be included in this rulemaking. A 
discussion of this analysis for MWCs is available in the Municipal 
Waste Combustor Supplement to February 28, 2022 Screening Assessment of 
Potential Emissions Reductions, Air Quality Impacts, and Costs from 
Non-EGU Emissions Units for 2026, which is available in the docket for 
this rule.
    Considering EPA's conclusion that MWCs should be included in this 
final rule if EPA applied the same criteria developed in the screening 
assessment for proposal, the findings from the OTC MWC report and 
recent MOU, the fact that many state RACT NOX rules apply to 
MWCs, and information received during public comment, the EPA finds 
that MWCs should be included in this final rule. Thus, the EPA is 
finalizing NOX emissions limits and compliance assurance 
requirements for large MWCs as defined in the regulatory text at Sec.  
52.46 and as described in this section.
    Comment: Some commenters did not support the inclusion of emissions 
limits for MWCs in the final rule. Some commenters suggested that the 
inclusion of NOX limits in a FIP is not necessary to 
continue to reduce NOX emissions from MWCs or to address 
interstate transport problems. Some commenters noted that many of the 
MWCs in the states covered by the proposal are already subject to RACT-
based NOX emissions limits that are below the current 
Federal NSPS NOX emissions limits for MWCs under 40 CFR part 
60, subparts Cb and Eb. One commenter noted that MWCs do not always 
account for a large percentage of statewide NOX emissions. 
Others suggested that voluntary industry actions are also driving 
downward trends of NOX emissions for some MWCs. Some 
commenters also asserted that regulation could interfere with state 
waste reduction policies and associated environmental considerations.
    Response: Regarding the comments that some MWCs are already subject 
to RACT NOX emissions limits, the EPA acknowledges that some 
states included in this rulemaking have promulgated RACT NOX 
emissions limits that apply to certain MWCs, including some that are 
lower than current MWC NSPS NOX emissions limits. The EPA 
does not consider a source to be exempt from this rulemaking just 
because the source may be subject to other regulatory requirements. As 
noted, the Agency did evaluate MWCs using the criteria developed in the 
screening assessment for proposal and has concluded that MWCs should be 
included in this rulemaking. In considering the emissions limits that 
are being finalized in this rulemaking, the EPA reviewed existing state 
RACT rules as described in section VI.C.6 of this document and the 
``Technical Support Document (TSD) for the Final Rule, Docket ID No. 
EPA-HQ-OAR-2021-0668, Non-EGU Sectors TSD'' (Mar. 2023), hereinafter 
referred to as Final Non-EGU Sectors TSD. We note that sources already 
subject to RACT NOX emissions limits that are equal to or 
more stringent than the limits finalized in this rulemaking will have 
the option to streamline regulatory requirements through the Title V 
permitting process.
    Regarding the statement that regulation could interfere with state 
waste reduction policies and associated environmental considerations, 
the EPA acknowledges that MWCs serve an important role in municipal 
solid waste management programs, and that many function as cogeneration 
facilities that produce electrical power for the power grid. The EPA 
also analyzed control costs and determined that the required 
NOX emissions limits for MWCs can be achieved at a 
reasonable cost, as described in section VI.C.6 of this document, the 
Final Non-EGU Sectors TSD, and the OTC MWC Report. Although the EPA 
does not expect these regulations to disrupt the ability of the 
industry to provide municipal solid waste and electric services, to the 
extent a facility is unable to comply with the standards due to 
technical impossibility or extreme economic hardship, the final rule 
includes provisions for facility operators to apply for a case-by-case 
alternative emissions limit. See section VI.C of this document and 40 
CFR 52.40(d). In addition, for MWC facilities that are unable to comply 
with the standard by the 2026 ozone season, the final rule includes 
provisions for requesting limited extensions of time to

[[Page 36735]]

comply. See section VI.C and 40 CFR 52.40(c).
b. Electric Generating Units Less Than or Equal to 25 MW
    The EPA has historically not included control requirements for 
emissions for electric generating units less than or equal to 25 MW of 
generation 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 percent 
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 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 emissions reductions from these 
small EGU sources as part of this rule. For instance, as explained in 
the EGU NOX Mitigation Strategies Final 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.\225\ Moreover, the EPA estimates that under 
6 percent of nationwide EGU emissions come from units that are less 
than 25 MW and not covered by current applicability criteria due to 
this size exemption threshold. Therefore, the EPA is not finalizing any 
emissions reductions for these units.
---------------------------------------------------------------------------

    \225\ 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.
---------------------------------------------------------------------------

    Comment: EPA received comment supporting the continued application 
of the 25 MW threshold.
    Response: Consistent with prior rules, the proposal, and 
stakeholder comment, EPA is continuing to apply its 25 MW applicability 
threshold for EGUs in this rulemaking. EPA did not find compelling 
comment to reverse its determination that (1) these sources offer low 
potential reductions, (2) have relatively high cost per ton, and (3) 
have high monitoring and other compliance burdens.
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 
altering in this rulemaking (see section VI.B.3 of this document)--
exempt some cogeneration units from coverage as EGUs under the trading 
program. The EPA is finalizing 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 the Group 3 emissions trading program. 
However, to the extent a cogeneration unit meets the applicability 
criteria for industrial non-EGU boilers covered by this rule, that unit 
will be subject to the relevant requirements and is not exempted by 
virtue of being a cogeneration unit.
    According to information contained in the EPA's Combined Heat and 
Power Partnership's document ``Catalog of CHP Technologies'',\226\ 
there are 4,226 CHP installations in the U.S. providing 83,317 MWe of 
electrical capacity. Over 99 percent 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 herewith 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.
---------------------------------------------------------------------------

    \226\ This document is available at: https://www.epa.gov/sites/default/files/2015-07/documents/catalog_of_chp_technologies.pdf.
---------------------------------------------------------------------------

    NOX emissions from rich burn reciprocating engine, gas 
turbine, and microturbine systems are low, ranging from 0.013 to 0.05 
lb/mmBtu. NOX emissions from lean burn reciprocating engine 
systems and gas-powered steam turbines systems range from 0.1 to 0.2 
lb/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 lb/mmBtu.
    Under the final 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. 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

[[Page 36736]]

power. 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 requested comment on requiring fossil fuel-fired boilers in 
the non-EGU industries identified in section VI.C of this document 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 rulemaking to fossil fuel-fired boilers at 
facilities in the same non-EGU industries that do not serve electricity 
generators.
    Comment: Some stakeholders support the continued exclusion of 
qualifying cogenerators from the EGU program, but suggested they be 
regulated as non-EGUs if they don't fit the EGU applicability criteria.
    Response: The EPA agrees that there is no basis within the four-
step framework to exempt cogeneration units that fall under the 
applicability criteria of the final rule for non-EGU boilers simply 
because they are cogeneration units. While cogeneration units do have 
environmental benefits as noted at proposal, some cogeneration unit-
types, particularly boilers, are estimated to have NOX 
emissions that would otherwise meet this rule's criteria at Step 3 for 
constituting ``significant contribution.'' These units can meet the 
emissions limits that are otherwise finalized for these unit types, and 
the EPA does not find a basis to exclude them simply because they may 
have other environmentally-beneficial attributes.
    These emissions limits are set forth in section VI.C.5 of this 
document. Therefore, the final requirements for non-EGUs do not exempt 
cogeneration units and any cogeneration emissions units meeting the 
applicability criteria for non-EGUs will be subject to the final 
emissions limits for the appropriate non-EGU emissions unit. Based on 
EPA's review of available data, across all of the non-EGU industries 
covered by this rule, there are four cogeneration boilers (two in Pulp 
and Papermill and two in Basic Chemical Manufacturing) that would meet 
the final rule's applicability criteria for non-EGU units and are 
included in the analysis of non-EGU emissions reduction potential in 
section V.C.2 of this document.
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 section 209), 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 final 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) \227\ 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.\228\
---------------------------------------------------------------------------

    \227\ US EPA. Our Nation's Air: Status and Trends Through 2019. 
https://gispub.epa.gov/air/trendsreport/2020/#home.
    \228\ 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.\229\ 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).
---------------------------------------------------------------------------

    \229\ Control of Air Pollution from Motor Vehicles: Tier 3 Motor 
Vehicle Emissions and Fuel Standards, 79 FR 23414 (April 28, 2014).
---------------------------------------------------------------------------

    Most recently, EPA finalized more stringent emissions standards for 
NOX and other pollution from heavy-duty trucks (Control of 
Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle 
Standards, 88 FR 4296, January 24, 2023). These standards will take 
effect beginning with model year 2027. 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.\230\ Reducing heavy-duty vehicle emissions nationally will 
improve air quality where the trucks are operating as well as downwind. 
The EPA's existing regulatory program for mobile sources will continue 
to reduce NOX emissions into the future.
---------------------------------------------------------------------------

    \230\ 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.
---------------------------------------------------------------------------

    Comment: The EPA received comments on ozone-precursor emissions 
from mobile sources, including cars, trucks, trains, ships, and planes. 
Commenters broadly encouraged the EPA to require emissions reductions 
from mobile sources in this rule. Commenters stated that the 
transportation sector plays a significant role in NOX 
pollution and ozone formation and urged the EPA to finalize emissions 
reductions for the transportation sector that will enable attainment of 
the 2015 ozone NAAQS. Some commenters noted that high proportions of 
NOX emissions in various upwind states are attributable to 
the transportation sector, and stated that EPA should have targeted 
emissions reductions from mobile sources first before requiring more 
stringent emissions controls from stationary sources in the same upwind 
states.
    Response: The EPA agrees with commenters that a variety of sources, 
including mobile sources in the transportation sector, produce 
NOX emissions that contribute to ozone air quality problems 
across the U.S. This rule, as with prior interstate transport actions, 
does not ignore those emissions, and it credits those on-the-books 
measures of states and the Federal Government within the four-step 
framework by including emissions and

[[Page 36737]]

emissions reductions from these sources in the emissions inventory for 
air quality modeling, which informs Steps 1 and 2 of this analysis. 
Thus, this rule accurately represents emissions from mobile sources 
that are used to evaluate the contribution of states to ozone air 
quality problems in other states. See section IV.C of this document.
    The EPA notes that its Step 3 analysis for this FIP does not assess 
additional emissions reductions opportunities from mobile sources. The 
EPA continues to believe that title II of the CAA provides the primary 
authority and process for reducing these emissions at the Federal 
level. EPA's various Federal mobile source programs, summarized above 
in this section, have delivered and are projected to continue to 
deliver substantial nationwide reductions in both VOCs and 
NOX emissions; these reductions from final rules 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 the EPA's authority to address 
such emissions through such means when regulating in place of the 
states under CAA section 110(c). See generally CAA section 209. See 
also 86 FR 23099.\231\ In any case, the existence of mobile source 
emissions noted by commenters does not lead to the conclusion that the 
EPA must require mobile source reductions in this rule or that the EPA 
has not properly identified ``source[s] or other type[s] of emissions 
activity'' in upwind states that ``significantly contribute'' for 
purposes of the Good Neighbor Provision. The EPA is committed to 
continuing the effective implementation and enforcement of current 
mobile source standards and continuing its efforts on new standards. 
The EPA will continue to work with state and local air agencies to 
incorporate emissions reductions from the transportation sector into 
required ozone attainment planning elements.
---------------------------------------------------------------------------

    \231\ This is not to say that states lack other options to 
reduce emissions from mobile sources. For example, a general list of 
types of transportation control measures can be found in CAA section 
108(f). In addition, in accordance with section 177, states may (but 
are not required to) adopt California vehicle emissions standards 
for which a waiver has been granted from the preemption provisions 
in section 209(a). States that decide to adopt California vehicle 
emissions standards may also choose to submit those standards to be 
included as a part of their SIP.
---------------------------------------------------------------------------

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 V.A of this document, 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 V.B.1 of this document), 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.\232\ The EGUs in the 
state are sufficiently well-controlled resulting in the lowest fossil-
fuel emissions rate and highest share of renewable generation among the 
23 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 emissions reductions required to 
eliminate significant contribution from any EGU sources in California.
---------------------------------------------------------------------------

    \232\ The only coal-fired power plant in California is the 63 MW 
Argus Cogeneration facility in Trona, California.
---------------------------------------------------------------------------

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

                 Table V.C.1-1--EGU Ozone-Season Emissions and Reduction Potential (Tons)--2023
----------------------------------------------------------------------------------------------------------------
                                                               Reduction potential (tons) for varying levels of
                                                                             technology inclusion
                                                             ---------------------------------------------------
                   State                      Baseline 2023                                         SCR/SNCR
                                                  OS NOX            SCR       SCR optimization   optimization +
                                                               optimization     + combustion       combustion
                                                                              control upgrades  control upgrades
----------------------------------------------------------------------------------------------------------------
Alabama....................................            6,412              32                32                32
Arkansas...................................            8,955              28                28                28
Illinois...................................            7,721              70                70               247
Indiana....................................           13,298             856               856               858
Kentucky...................................           13,900             299               901               901
Louisiana..................................            9,974             515               515               611
Maryland...................................            1,214               0                 0                 8
Michigan...................................           10,746               4                 4                19
Minnesota..................................            5,643              98                98               139
Mississippi................................            6,283              73               984               984
Missouri...................................           20,094           7,339             7,339             7,497
Nevada.....................................            2,372               4                 4                 4
New Jersey.................................              915             143               143               143
New York...................................            3,977              64                64                64
Ohio.......................................           10,264           1,154             1,154             1,154
Oklahoma...................................           10,470             199               890               890
Pennsylvania...............................            8,573             336               336               436
Texas......................................           41,276             909               909             1,142
Utah.......................................           15,762               7                 7                 7
Virginia...................................            3,329             164               242               263
West Virginia..............................           14,686             554             1,099             1,380

[[Page 36738]]

 
Wisconsin..................................            6,321               7                 7                26
                                            --------------------------------------------------------------------
    Total..................................          222,184          12,854            15,681            16,832
----------------------------------------------------------------------------------------------------------------
* The EPA shows reduction potential from state-of-the-art LNB upgrade as near-term emissions controls, but
  explains in section V.B and VI.A of this document that this reduction potential would not be implemented until
  2024.


                                    Table V.C.1-2--EGU Ozone-Season Emissions and Reduction Potential (Tons)--2026 *
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Reduction potential (tons) for varying levels of technology
                                                                                                                  inclusion
                                                                                   ---------------------------------------------------------------------
                                                                                                                                            SCR/SNCR
                              State                                 Baseline 2026                                         SCR/SNCR       optimization +
                                                                        OS NOX            SCR       SCR optimization   optimization +      combustion
                                                                                     optimization     + combustion       combustion     control upgrades
                                                                                                    control upgrades  control upgrades     + SCR/SNCR
                                                                                                                                            retrofits
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..........................................................            6,371              32                32                32               604
Arkansas.........................................................            8,728              28                28                28             4,697
Illinois.........................................................            6,644              70                70               230             1,281
Indiana..........................................................            9,468             768               768               770             1,333
Kentucky.........................................................           13,211             299               739               739             5,303
Louisiana........................................................            9,704             515               515               611             5,894
Maryland.........................................................              901              51                51                59                59
Michigan.........................................................            7,790               4                 4                19             1,959
Minnesota........................................................            4,197              98                98               139             1,613
Mississippi......................................................            6,022              73               984               984             3,938
Missouri.........................................................           18,612           7,339             7,339             7,497            11,231
Nevada...........................................................            1,146               4                 4                 4                 4
New Jersey.......................................................              915             143               143               143               143
New York.........................................................            3,977              64                64                64               589
Ohio.............................................................            9,083           1,154             1,154             1,154             1,154
Oklahoma.........................................................           10,259             199               890               890             5,968
Pennsylvania.....................................................            8,362             352               352               452             1,204
Texas............................................................           39,684             909               909             1,142            15,980
Utah.............................................................            9,930               7                 7                 7             7,338
Virginia.........................................................            3,019             164               242               263               646
West Virginia....................................................           13,185             401               947             1,227             3,507
Wisconsin........................................................            5,016               7                 7                26               623
                                                                  --------------------------------------------------------------------------------------
    Total........................................................          196,225          12,680            15,346            16,480            75,067
--------------------------------------------------------------------------------------------------------------------------------------------------------
* The EPA shows all emissions reduction potential identified for assumed SCR retrofits in the Step 3 analytic year 2026, but explains in sections V.B
  and VI.A of this document that for Step 4 implementation this emissions reduction potential will be phased in during the 2026 and 2027 ozone season
  control periods.

2. Non-EGU or Industrial Source Emissions Reduction Potential
    As described in the memorandum titled ``Summary of Final Rule 
Applicability Criteria and Emissions Limits for Non-EGU Emissions 
Units, Assumed Control Technologies for Meeting the Final Emissions 
Limits, and Estimated Emissions Units, Emissions Reductions, and 
Costs,'' the EPA uses the 2019 emissions inventory, the list of 
emissions units estimated to be captured by the applicability criteria, 
the assumed control technologies that would meet the emissions limits, 
and information on control efficiencies and default cost/ton values 
from the CMDB, to estimate NOX emissions reductions and 
costs for the year 2026. The estimates using the 2019 inventory and 
information from the CMDB identify proxies for emissions units, as well 
as emissions reductions, and costs associated with the assumed control 
technologies that would meet the final emissions limits. Emissions 
units subject to the final rule emissions limits may differ from those 
estimated in this assessment, and the estimated emissions reductions 
from and costs to meet the final rule emissions limits may also differ 
from those estimated in this assessment. The costs do not include 
monitoring, recordkeeping, reporting, or testing costs.
    Table V.C.2-1 summarizes the industries, estimated emissions unit 
types, assumed control technologies, estimated annual costs (2016$), 
and estimated ozone season emissions reductions in 2026, and Table 
V.C.2-2 summarizes the estimated reductions by state.

[[Page 36739]]



 Table V.C.2-1--By Industry in 2026, Estimated Emissions Unit Types, Assumed Control Technologies, Annual Costs
                         (2016$), and Estimated Emissions Reductions (Ozone Season Tons)
----------------------------------------------------------------------------------------------------------------
                                                              Assumed control
                                                             technologies that     Annual costs    Ozone season
        Industry/industries          Emissions unit type    meet final emissions      (2016$)        emissions
                                                                   limits                           reductions
----------------------------------------------------------------------------------------------------------------
Pipeline Transportation of Natural  Reciprocating          NSCR or Layered           385,463,197          32,247
 Gas.                                Internal Combustion    Combustion, Layered
                                     Engine.                Combustion, SCR,
                                                            NSCR.
Cement and Concrete Product         Kiln.................  SNCR.................      10,078,205           2,573
 Manufacturing.
Iron and Steel Mills and            Reheat Furnaces......  LNB..................       3,579,294             408
 Ferroalloy Manufacturing.
Glass and Glass Product             Furnaces.............  LNB..................       7,052,088           3,129
 Manufacturing.
Iron and Steel Mills and            Boilers..............  SCR, LNB + FGR.......       8,838,171             440
 Ferroalloy Manufacturing.
Metal Ore Mining..................  .....................  .....................         621,496              18
Basic Chemical Manufacturing......  .....................  .....................      49,697,848           1,748
Petroleum and Coal Products         .....................  .....................       5,128,439             147
 Manufacturing.
Pulp, Paper, and Paperboard Mills.  .....................  .....................      62,268,540           1,836
Solid Waste Combustors and          Combustors or          ANSCR or LN\TM\ and        38,949,560           2,071
 Incinerators.                       Incinerators.          SNCR.
                                                                                 -------------------------------
    Totals........................  .....................  .....................     571,676,839          44,616
----------------------------------------------------------------------------------------------------------------


  Table V.C.2-2--Estimated Emissions Reductions (Ozone Season Tons) by
                          Upwind State in 2026
------------------------------------------------------------------------
                                              2019 OS         OS NOX
                  State                     emissions *     reductions
------------------------------------------------------------------------
AR......................................           8,790           1,546
CA......................................          16,562           1,600
IL......................................          15,821           2,311
IN......................................          16,673           1,976
KY......................................          10,134           2,665
LA......................................          40,954           7,142
MD......................................           2,818             157
MI......................................          20,576           2,985
MO......................................          11,237           2,065
MS......................................           9,763           2,499
NJ......................................           2,078             242
NV \233\................................           2,544               0
NY......................................           5,363             958
OH......................................          18,000           3,105
OK......................................          26,786           4,388
PA......................................          14,919           2,184
TX......................................          61,099           4,691
UT......................................           4,232             252
VA......................................           7,757           2,200
WV......................................           6,318           1,649
                                         -------------------------------
    Totals..............................         302,425          44,616
------------------------------------------------------------------------
* The 2019 OS season emissions are calculated as 5/12 of the annual
  emissions from the following two emissions inventory files:
  nonegu_SmokeFlatFile_2019NEI_POINT_20210721_controlupdate_13sep2021_v0
  and
  oilgas_SmokeFlatFile_2019NEI_POINT_20210721_controlupdate_13sep2021_v0
  .

    In Table  V.C.2-3 by industry and emissions unit type, the EPA 
provides a summary of the control technologies applied and their 
average costs across all of the non-EGU emissions units. The average 
cost per ton values range from $939 to $14,595 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.
---------------------------------------------------------------------------

    \233\ We are not aware of existing non-EGU emissions units in 
Nevada that meet the applicability criteria for non-EGUs in the 
final rule. If any such units in fact exist, they would be subject 
to the requirements of the rule just as in any other state. In 
addition, any new emissions unit in Nevada that meets the 
applicability criteria in the final rule will be subject to the 
final rule's requirements. See section III.B.1.d.

  Table V.C.2-3--By Industry, Emissions Unit Type, Assumed Control Technologies, and Estimated Average Cost per
                          Ton by Control Technology Across All Non-EGU Emissions Units
----------------------------------------------------------------------------------------------------------------
                                                                                                       Average
                                                                              Assumed control          cost/ton
           Industry/industries                 Emissions unit type         technologies that meet       values
                                                                           final emissions limits      (2016$)
----------------------------------------------------------------------------------------------------------------
Pipeline Transportation of Natural Gas...  Reciprocating Internal       NSCR or Layered Combustion,        4,981
                                            Combustion Engine.           Layered Combustion, SCR,
                                                                         NSCR.
Cement and Concrete Product Manufacturing  Kiln.......................  SNCR.......................        1,632

[[Page 36740]]

 
Iron and Steel Mills and Ferroalloy        Reheat Furnaces............  LNB........................        3,656
 Manufacturing.
Glass and Glass Product Manufacturing....  Furnaces...................  LNB........................          939
Iron and Steel Mills and Ferroalloy        Boilers....................  SCR or LNB + FGR...........        8,369
 Manufacturing.
Metal Ore Mining.........................  ...........................  ...........................       14,595
Basic Chemical Manufacturing.............  ...........................  ...........................       11,845
Petroleum and Coal Products Manufacturing  ...........................  ...........................       14,582
Pulp, Paper, and Paperboard Mills........  ...........................  ...........................       14,134
Solid Waste Combustors and Incinerators..  Combustors or Incinerators.  ANSCR or LN\TM\ and SNCR...        7,836
                                                                                                    ------------
    Overall Average Cost/Ton.............  ...........................  ...........................        5,339
----------------------------------------------------------------------------------------------------------------

    Refer to the memorandum titled ``Summary of Final Rule 
Applicability Criteria and Emissions Limits for Non-EGU Emissions 
Units, Assumed Control Technologies for Meeting the Final Emissions 
Limits, and Estimated Emissions Units, Emissions Reductions, and 
Costs'' for additional estimates--including by industry and by state. 
These estimates are proxy estimates, and the EPA also did not prepare 
detailed engineering analyses for the industries, facilities, and 
individual emissions units identified for the final rule. Emissions 
units subject to the final rule emissions limits may differ from those 
estimated in this assessment, and the estimated emissions reductions 
from and costs to meet the final rule emissions limits may also differ 
from those estimated in this assessment.
    Comment: Regarding the marginal cost threshold of $7,500/ton used 
to assess potential emissions reductions in the non-EGU screening 
assessment prepared for proposal, commenters raised a range of 
questions, including (1) why the EPA used a marginal cost threshold 
that is much higher than the $2,000/ton threshold used in the 2021 
Revised CSAPR Update Rule, (2) why the EPA used a ``one size fits all'' 
approach for addressing the estimated cost and actual emissions 
reductions achievable, particularly for existing sources of 
NOX emissions, (3) why the EPA set a $7,500/ton marginal 
cost threshold for all non-EGUs, despite acknowledging the 
heterogeneity of industry, emissions unit types and control options and 
failing to consider the actual costs associated with achieving the 
proposed reductions at different types of emissions units in order to 
artificially inflate the marginal cost threshold and to justify 
otherwise cost-prohibitive NOX control technologies. 
Commenters also stated that controls for their industry are not cost-
effective using the EPA's presumptive value of $7,500/ton and that the 
value may not be technically feasible to apply to existing sources that 
would have to retrofit controls.
    Response: The EPA notes that the primary purpose of the Screening 
Assessment of Potential Emissions Reductions, Air Quality Impacts, and 
Costs from Non-EGU Emissions Units for 2026 (non-EGU screening 
assessment) was to identify potentially impactful industries and 
emissions unit types for further evaluation.\234\ In the non-EGU 
screening assessment memorandum we presented an analytical framework to 
further analyze potential emissions reductions and costs and included 
proxy estimates for 2026.
---------------------------------------------------------------------------

    \234\ The non-EGU screening assessment memorandum is available 
in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0150.
---------------------------------------------------------------------------

    As noted in section V.D. of this document, at proposal the EPA 
found that based on data available at that time and for the purposes of 
the non-EGU screening assessment, it appeared that a $7,500 marginal 
cost-per-ton threshold could be used as a proxy to identify cost-
effective emissions control opportunities. Also, the $7,500 marginal 
cost-per-ton threshold is higher than the cost-per-ton value used in 
the Revised Cross-State Air Pollution Rule Update because that 
rulemaking assessed significant contribution for the less protective 
2008 ozone NAAQS, and it is reasonable when assessing significant 
contribution associated with the more protective 2015 ozone NAAQS, that 
a potentially more costly universe of emissions controls and related 
potential reductions should be included in the analysis.\235\ Similar 
to the role of cost-effectiveness thresholds the EPA uses at Step 3 to 
evaluate EGU emissions control opportunities, this threshold is not 
intended to represent the maximum cost any facility may need to expend 
but is rather intended to be a representative figure for evaluating 
technologies to allow for a relative comparison between different 
levels of control stringency. The EPA's potential cost threshold for 
non-EGU controls at proposal was intended to serve a similar 
representative purpose. Based on the EPA's updated analysis for this 
final rule, the EPA recognizes that the $7,500/ton threshold does not 
reflect the full range of cost-effectiveness values that are likely 
present across the many different types of non-EGU industries and 
emissions units assessed.
---------------------------------------------------------------------------

    \235\ As the amount of air pollution that is allowed in the 
ambient air is reduced (i.e., when a NAAQS is revised), it is 
reasonable to expect that further emissions reductions may be 
necessary to bring areas into attainment with that more protective 
standard. At the same time, the available remaining emissions 
reduction opportunities will likely have become more costly compared 
to a prior period, because other CAA requirements, including such as 
earlier transport rules, will have consumed those emissions 
reduction opportunities that were the least costly. The EPA noted 
this same possibility in the original CSAPR rulemaking, see 76 FR 
48210.
---------------------------------------------------------------------------

    While the potentially impactful industries (identified in Step 1 of 
the analytical framework presented in the non-EGU screening assessment) 
were directly used, the proxy estimates for emissions unit types, 
emissions reductions, and costs from the non-EGU screening assessment 
were not directly used to establish applicability thresholds and 
emissions limits in the proposal. To further evaluate the impactful 
industries and emissions unit types and establish the proposed 
emissions limits, the EPA reviewed RACT rules, NSPS rules, NESHAP 
rules, existing technical studies (e.g., Ozone Transport Commission, 
Technical Information Oil and Gas Sector Significant Stationary Sources 
of NOX Emissions, October 17, 2012), rules in approved SIP 
submittals, consent decrees, and permit limits.\236\
---------------------------------------------------------------------------

    \236\ This review is detailed in the Final Non-EGU Sectors TSD 
available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0145.

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

[[Page 36741]]

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 finalizes a 
determination regarding the appropriate level of uniform NOX 
control stringency that would collectively eliminate significant 
contribution to downwind nonattainment and maintenance receptors. Based 
on the air quality results presented in this section, we find that the 
emissions control strategies that were identified and evaluated in 
sections V.B and V.C of this document and found to be both cost-
effective and feasible, deliver meaningful air quality benefits through 
projected reductions in ozone levels across the linked downwind 
nonattainment and maintenance receptors in the relevant analytic years 
2023 and 2026. Further, EPA finds the emissions control strategies in 
upwind states that would deliver these benefits to be widely available 
and in use at many other similar EGU and non-EGU facilities throughout 
the country, particularly in those areas that have historically or now 
continue to struggle to attain and maintain the 2015 ozone NAAQS. 
Applying these emissions control strategies on a uniform basis across 
all linked upwind states continues to constitute an efficient and 
equitable solution to the problem of allocating upwind-state 
responsibility for the elimination of significant contribution. This 
approach continues to effectively address the ``thorny'' causation 
problem of interstate pollution transport for regional-scale pollutants 
like ozone that transport over large distances and are affected by the 
vagaries of meteorology. EME Homer City, 572 U.S. at 514-16. It 
requires the most impactful sources in each state that has been found 
to contribute to ozone problems in other states to come up to minimum 
standards of environmental performance based on demonstrated 
NOX pollution-control technology. Id. at 519. When the 
effects of these emissions reductions are assessed collectively across 
the hundreds of EGU and non-EGU industrial sources that are subject to 
this rule, the cumulative improvements in ozone levels at downwind 
receptors, while they may vary to some extent, are both measurable and 
meaningful and will assist downwind areas in attaining and maintaining 
the 2015 ozone NAAQS.
    In addition to the findings of cost-effectiveness, feasibility and 
widespread availability that support EPA's identification of the 
appropriate level of emissions-control stringency at Step 3 discussed 
in sections V.B and V.C, the findings regarding air quality improvement 
in this section--as in prior transport rules--are a central component 
of our Step 3 analytic findings as to the definition of ``significant 
contribution.'' EPA's assessment of air quality improvement for all of 
the emissions control strategies included shows continued air quality 
improvement with each additional control strategy measure. Within the 
group of selected control strategies for EGUs and non-EGUs no clear 
``knee-in-the-curve'' is evident; i.e., there is no point at which 
there is a noticeable decline in the rate of air quality improvement up 
through the control stringency level selected. However, if EPA were to 
go beyond the selected control stringency through inclusion of 
additional EGU or non-EGU NOX mitigation technologies for 
the covered sources and unit-types that are, at least on the record of 
this action, not widely available, uncertain or untested, and/or far 
more costly, a ``knee-in-the-curve'' does materialize, where the 
incremental air quality benefit per dollar spent per ton on mitigation 
measures plateaus even as costs increase dramatically. In the Revised 
CSAPR Update, EPA explained that a knee in the curve ``is not on its 
own a justification for not requiring reductions beyond that point,'' 
86 FR 23107, but does indicate that it is a useful indicator for 
informing potential stopping points. The observation that no ``knee-in-
the-curve'' materializes at the stringency levels up through that 
selected by EPA supports EPA's identified control stringency.
    Further, as the Supreme Court has 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. While the ultimate purpose of 
the good neighbor provision is to eliminate significant contribution 
and not necessarily to resolve downwind areas' nonattainment and 
maintenance problems, we have evaluated the expected attainment status 
at each identified receptor as we examine the air quality effects of 
the different emissions control strategies identified. As discussed 
further in this section, the EPA notes that multiple receptors shift 
into projected attainment status or shift from projected nonattainment 
to maintenance status up through the stringency level ultimately 
selected by EPA. (And all receptors show improvement in air quality 
even if their status does not change.) These analytic findings at Step 
3 cement EPA's identification of the selected EGU and non-EGU 
mitigation measures as the appropriate control stringency to fulfill 
its statutory obligation to eliminate significant contribution for the 
2015 ozone NAAQS for the covered states. The EPA also evaluated whether 
the final 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 of 
NAAQS air quality contribution threshold at a lower cost threshold. The 
Agency finds no overcontrol from this rule. See section V.D.4 of this 
document.
1. EGU Assessment
    For EGUs, the EPA examined the emissions reduction potential 
associated with each EGU emissions control technology (presented in 
section V.C.1 of this document) 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 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.

[[Page 36742]]

    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 starting in the 
2026 ozone season at $11,000 and $7,700 per ton respectively. For all 
but 3 of the affected states (Alabama, Minnesota, and Wisconsin, which 
are no longer linked in 2026 at Steps 1 and 2 in EPA's base case air 
quality modeling for this final rule), EPA's evaluation shows that the 
effective emissions rate performance across EGUs consistent with the 
full 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 Final Rule TSD for details).
    To assess downwind air quality impacts for the nonattainment and 
maintenance receptors identified in section IV.D of this document, 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 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 ``fair 
share'' of the responsibility for resolving a nonattainment or 
maintenance problem as a part of the over-control evaluation.\237\
---------------------------------------------------------------------------

    \237\ For EGUs, this analysis for the Connecticut receptors 
shows no EGU reduction potential in Connecticut 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 Final 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 0.06 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 no receptors switch 
from maintenance to attainment or from nonattainment to maintenance 
with these mitigation strategies in place. Table V.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 0.47 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 Larimer County, Colorado (Monitor 080690011), 
switching from maintenance to attainment and two receptors (one in 
Fairfield County, Connecticut (Monitor 90013007), and one in Galveston, 
Texas (Monitor ID 481671034)) switching from nonattainment to 
maintenance with these mitigation strategies in place.\238\ Table 
V.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 Final Rule TSD and to the Ozone AQAT included in the 
docket for this rule.
---------------------------------------------------------------------------

    \238\ 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 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 action are further discussed in 
sections V.D.3 and V.D.4 of this document.

[[Page 36743]]



                              Table V.D.1-1--Air Quality at the Receptors in 2023 From EGU Emissions Control Technologies a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Average DV (ppb)                  Max DV (ppb)
                                                                                         ---------------------------------------------------------------
            Monitor ID No.                       State                    County             Baseline        SCR/SNCR        Baseline        SCR/SNCR
                                                                                           (engineering   optimization +   (engineering   optimization +
                                                                                             analysis)      LNB upgrade      analysis)      LNB upgrade
--------------------------------------------------------------------------------------------------------------------------------------------------------
40278011.............................  Arizona.................  Yuma...................           70.36           70.34           72.05           72.04
80350004.............................  Colorado................  Douglas................           71.12           71.10           71.71           71.70
80590006.............................  Colorado................  Jefferson..............           72.63           72.61           73.32           73.31
80590011.............................  Colorado................  Jefferson..............           73.29           73.27           73.89           73.87
80690011.............................  Colorado................  Larimer................           70.79           70.78           71.99           71.98
90010017.............................  Connecticut.............  Fairfield..............           71.62           71.56           72.22           72.16
90013007.............................  Connecticut.............  Fairfield..............           72.99           72.90           73.89           73.80
90019003.............................  Connecticut.............  Fairfield..............           73.32           73.25           73.62           73.55
90099002.............................  Connecticut.............  New Haven..............           70.61           70.51           72.71           72.61
170310001............................  Illinois................  Cook...................           68.13           68.11           71.82           71.80
170314201............................  Illinois................  Cook...................           67.92           67.88           71.41           71.37
170317002............................  Illinois................  Cook...................           68.47           68.37           71.27           71.17
350130021............................  New Mexico..............  Dona Ana...............           70.83           70.82           72.13           72.12
350130022............................  New Mexico..............  Dona Ana...............           69.73           69.72           72.43           72.42
350151005............................  New Mexico \b\..........  Eddy...................  ..............  ..............  ..............  ..............
350250008............................  New Mexico..............  Lea....................  ..............  ..............  ..............  ..............
480391004............................  Texas...................  Brazoria...............           70.59           70.52           72.69           72.62
481210034............................  Texas...................  Denton.................           69.93           69.88           71.73           71.68
481410037............................  Texas...................  El Paso................           69.82           69.81           71.43           71.41
481671034............................  Texas...................  Galveston..............           71.82           71.70           73.13           73.01
482010024............................  Texas...................  Harris.................           75.33           75.25           76.93           76.85
482010055............................  Texas...................  Harris.................           71.19           71.10           72.20           72.10
482011034............................  Texas...................  Harris.................           70.32           70.25           71.52           71.45
482011035............................  Texas...................  Harris.................           68.01           67.94           71.52           71.45
490110004............................  Utah....................  Davis..................           71.88           71.87           74.08           74.07
490353006............................  Utah....................  Salt Lake..............           72.48           72.47           74.07           74.06
490353013............................  Utah....................  Salt Lake..............           73.21           73.20           73.71           73.70
550590019............................  Wisconsin...............  Kenosha................           70.75           70.65           71.65           71.55
551010020............................  Wisconsin...............  Racine.................           69.59           69.46           71.39           71.25
551170006............................  Wisconsin...............  Sheboygan..............           72.64           72.46           73.54           73.36
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Average AQ Change Relative to Base (ppb)............................................  ..............  ..............  ..............            0.06
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Total PPB Change Across All Receptors Relative to Base \c\..........................  ..............  ..............  ..............            1.58
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ The EPA notes that the design values reflected in tables V.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 Final Rule TSD.
\b\ New Mexico Eddy and Lea monitors have no values in tables V.D.1-1 and 1-2 as EPA does not have calibration factors for these monitors as no
  contributions were calculated for them from the proposal AQ modeling
\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 VIII of this document provides a more complete picture of the air quality impacts of the final
  rule.


                                 Table V.D.1-2--Air Quality at Receptors in 2026 From EGU Emissions Control Technologies
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Average DV (ppb)                  Max DV (ppb)
                                                                                         ---------------------------------------------------------------
                                                                                                             SCR/SNCR                        SCR/SNCR
            Monitor ID No.                       State                    County             Baseline     optimization +     Baseline     optimization +
                                                                                           (engineering    LNB upgrade +   (engineering    LNB upgrade +
                                                                                             analysis)       SCR/SNCR        analysis)       SCR/SNCR
                                                                                                             retrofit                        retrofit
--------------------------------------------------------------------------------------------------------------------------------------------------------
40278011.............................  Arizona.................  Yuma...................           69.87           69.84           71.47           71.44
80590006.............................  Colorado................  Jefferson..............           71.70           71.36           72.30           71.95
80590011.............................  Colorado................  Jefferson..............           72.06           71.59           72.66           72.19
80690011.............................  Colorado................  Larimer................           69.84           69.54           71.04           70.73
90013007.............................  Connecticut.............  Fairfield..............           71.25           70.98           72.06           71.78
90019003.............................  Connecticut.............  Fairfield..............           71.58           71.34           71.78           71.54
350130021............................  New Mexico..............  Dona Ana...............           70.06           69.89           71.36           71.19
350130022............................  New Mexico..............  Dona Ana...............           69.17           69.00           71.77           71.60
350151005............................  New Mexico..............  Eddy...................  ..............  ..............  ..............  ..............
350250008............................  New Mexico..............  Lea....................  ..............  ..............  ..............  ..............
480391004............................  Texas...................  Brazoria...............           69.89           68.96           72.02           71.06
481671034............................  Texas...................  Galveston..............           71.29           70.02           72.51           71.22
482010024............................  Texas...................  Harris.................           74.83           73.86           76.45           75.46
490110004............................  Utah....................  Davis..................           69.90           69.34           72.10           71.52
490353006............................  Utah....................  Salt Lake..............           70.50           69.96           72.10           71.55
490353013............................  Utah....................  Salt Lake..............           71.91           71.45           72.31           71.84
551170006............................  Wisconsin...............  Sheboygan..............           70.83           70.51           71.73           71.41
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Average AQ Change Relative to Base (ppb)............................................  ..............  ..............  ..............            0.47
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Total PPB Change Across All Receptors Relative to Base (ppb)........................  ..............  ..............  ..............            7.04
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 36744]]

    Figures 1 and 2 to section V.D.1 of this document, included in 
Appendix I of the Ozone Transport Policy Analysis Final 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 V.D.1 
of this document reflects emissions reductions commensurate with 
optimization of existing SNCRs and SCRs. Figure 2 to section V.D.1 of 
this document 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 V.D.1 of this document. 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 technologies. While 
all major technology breakpoints identified in sections V.B and V.C of 
this document show continued air quality improvements at problematic 
receptors and at cost and technology 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 uniform 
control stringency that is an appropriate reflection of those readily 
available and widely implemented emissions reduction strategies that 
will have meaningful downwind air quality impact.
    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 66 percent 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.\239\ Similarly, 
the Clean Air Interstate Rule established emissions reductions 
requirements in 2006 that assumed SCR would be installed on another 58 
units (15 GW) 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.\240\
---------------------------------------------------------------------------

    \239\ 63 FR 57448.
    \240\ 71 FR 25345.
---------------------------------------------------------------------------

    Basing emissions 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 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-fired generating resources in states along the Northeast Corridor 
such as Connecticut, Delaware, New Jersey, New York, and Massachusetts 
all being retrofitted with SCR.\241\ The Maryland Code of Regulations 
requires coal-fired sources to operate existing SCR controls or install 
SCR controls by specified dates.\242\ 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.\243\ Unit-level 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.\244\
---------------------------------------------------------------------------

    \241\ EPA-HQ-OAR-2020-0272. Comment letter from Attorneys 
General of NY, NJ, CT, DE, MA.
    \242\ COMAR 26.11.38 (control of NOX Emissions from 
Coal-Fired Electric Generating Units).
    \243\ 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.
    \244\ 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 V.D.1 of this document,\245\ 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 
V.D.1 of this document \246\ highlights (1) the continuous connection 
between identified emissions 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.
---------------------------------------------------------------------------

    \245\ Included in Appendix I of the Ozone Transport Policy 
Analysis Final Rule TSD, which is available in the docket for this 
rulemaking.
    \246\ Included in Appendix I of the Ozone Transport Policy 
Analysis Final Rule TSD, which is available in the docket for this 
rulemaking.
---------------------------------------------------------------------------

    Additional considerations that are unique to EGUs provide 
additional support for EPA's determination to include SCR and SNCR 
optimization as part of the identified near-term control stringency, 
including:

[[Page 36745]]

     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 EGU emissions reduction potential and associated 
air quality improvements estimated to start in 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 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 is 
projected to result in nearly 73,000 tons of NOX reduction 
(approximately 40 percent of the 2026 baseline level) for the 19 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 receptor for the 
2015 ozone NAAQS. Figure 2 to section V.D.1 of this document \247\ 
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 emissions mitigation measures examined here fail to produce 
corresponding downwind air quality improvements.
---------------------------------------------------------------------------

    \247\ Included in Appendix I of the Ozone Transport Policy 
Analysis Final Rule TSD, which is available in the docket for this 
rulemaking.
---------------------------------------------------------------------------

    The EPA is determining that the appropriate EGU control stringency 
is commensurate with the full operation of all existing post-combustion 
controls (both SCRs and SNCRs) and state-of-the-art combustion control 
upgrades for those states linked to downwind nonattainment or 
maintenance receptors 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 V.B of this document and in the EGU 
NOX Mitigation Strategies Final 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 
combined cycle and simple cycle combustion turbines). The emissions 
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 units (rather than different pollution control 
technologies). 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 in this section, the EPA did analyze the cost, potential 
reductions, and air quality impact of these additional measures to 
affirm that they do not merit inclusion in the final stringency for 
this action. That analysis shows the potential emissions reductions and 
air quality improvements from these additional measures occur beyond a 
notable ``knee-in-the-curve'' breakpoint. 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 
capturing this effect (located in Appendix I of the Ozone Transport 
Policy Analysis Final Rule TSD) illustrates the significant decline in 
cost-effectiveness of reductions if these measures had been included in 
EPA's final stringency.\248\
---------------------------------------------------------------------------

    \248\ This is not to discount the potential effectiveness of 
these or other NOX mitigation strategies outside the 
context of this rulemaking, which addresses regional ozone transport 
on a nationwide basis based on the present record. 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 finds on the present 
record that this rule is a complete remedy to the problem of 
interstate transport for the 2015 ozone NAAQS for the covered 
states, 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).
---------------------------------------------------------------------------

2. Non-EGU Assessment
    Using a 2019 emissions inventory, the list of emissions units 
estimated to be captured by the applicability criteria, the assumed 
control technologies that would meet the emissions limits, and 
information on control efficiencies and default cost/ton values from 
the control measures database, the EPA estimated NOX 
emissions reductions and costs for the year 2026. Given the EPA's 
conclusion that the 2026 ozone season is the earliest date by which the 
required controls can be installed across the identified non-EGU 
industries, the EPA assessed the effects of these controls in 2026 
under its multi-factor test. In the assessment, we matched emissions 
units by Source Classification Code (SCC) from the inventory to the 
applicable control technologies in the CMDB. We modified SCC codes as 
necessary to match control technologies to inventory records. For 
additional details about the steps taken to estimate emissions units, 
emissions reductions, and costs, see the memorandum titled ``Summary of 
Final Rule Applicability Criteria and Emissions Limits for Non-EGU 
Emissions Units, Assumed Control Technologies for Meeting the Final 
Emissions Limits, and Estimated Emissions Units, Emissions Reductions, 
and Costs'' available in the docket. The estimates using the 2019 
inventory and information from the CMDB identify proxies for emissions 
units, as well as emissions reductions, and costs associated with the 
assumed control

[[Page 36746]]

technologies that would meet the final emissions limits. Emissions 
units subject to the final rule emissions limits may differ from those 
estimated in this assessment, and the estimated emissions reductions 
from, and costs to meet, the final rule emissions limits may also 
differ from those estimated in this assessment. The costs do not 
include monitoring, recordkeeping, reporting, or testing costs.
    After reviewing public comments and updating some of the data used 
to provide an accurate assessment of the likely potential emissions 
reductions that could be achieved from the identified emissions units 
in the industries analyzed for proposal, the EPA finds that in general, 
these emissions reductions (with some modifications from proposal) are 
necessary to eliminate significant contribution at Step 3. The EPA's 
use of the analytical framework presented in the non-EGU screening 
assessment to identify potentially impactful industries and emissions 
unit types in the proposal remains valid. The EPA's criteria were 
intended to identify industries and emissions unit types that on a 
broad scale impact multiple receptors to varying degrees. The EPA 
focused its non-EGU screening assessment on (1) emissions and potential 
emissions reductions from these industries and emissions units and (2) 
the potential impact that emissions reductions from those industries 
and emissions units could deliver to the receptors.
    While commenters criticized the analytical framework in the non-EGU 
screening assessment for assuming potentially unachievable emissions 
reductions at Step 3, or for not corresponding to a precise list of 
emissions units that would be covered at Step 4, these comments did not 
offer an alternative methodology for the Step 3 analysis to identify 
those industries and emissions units that potentially have the greatest 
impact and therefore should be scrutinized more closely for emissions 
reduction opportunities.\249\ Further, contrary to some commenters' 
assertions, the EPA's assessment did not result in an unbounded scope 
of regulation of industrial sources. Of the approximately 40 industries 
defined by North American Industry Classification System codes the EPA 
analyzed, only seven industries were identified as having emissions and 
potential emissions reduction opportunities that met the EPA's air 
quality criteria for further assessment.
---------------------------------------------------------------------------

    \249\ For example, while the EPA has found it appropriate to 
limit the scope of emissions units that would be subject to 
emissions limits and controls in the iron and steel industry in 
light of comments regarding certain sources' inability to meet the 
EPA's proposed emission limits, this does not alter the EPA's 
determination that this industry is an impactful industry and that 
certain emissions controls should still be required.
---------------------------------------------------------------------------

    At proposal, the EPA found that based on data available at that 
time and for the purposes of the screening assessment, it appeared that 
a $7,500 marginal cost-per-ton threshold could be used as a proxy to 
identify cost-effective emissions control opportunities. Similar to the 
role of cost-effectiveness thresholds the EPA uses at Step 3 to 
evaluate EGU emissions control opportunities, this threshold is not 
intended to represent the maximum cost any facility may need to expend 
but is rather intended to be a representative figure for evaluating 
technologies to allow for a relative comparison between different 
levels of control stringency. For example, in the EGU analysis, the 
$11,000/ton average cost threshold for an SCR retrofit represents a 
range of SCR retrofit costs for units for which the 90th percentile 
cost-per-ton is roughly $21,000. See section V.B.a of this document. 
The EPA's potential cost threshold for non-EGU controls at proposal was 
intended to serve a similar representative purpose. We respond briefly 
to comments regarding the use of the $7,500/ton threshold in section 
V.C of this document. Comments regarding the screening assessment are 
further addressed in section 2.2 of the response to comments document 
in the docket.
    Based on the EPA's updated analysis for this final rule, the EPA 
recognizes that the $7,500/ton threshold does not reflect the full 
range of cost-effectiveness values that are likely present across the 
many different types of non-EGU industries and emissions units 
assessed. However, the EPA nonetheless finds that, with some 
adjustments from proposal, the overall mix of emissions controls it 
identified at proposal is appropriate to eliminate significant 
contribution to nonattainment or interference with maintenance in 
downwind areas. In the final analysis, we find that the average cost-
per-ton of emissions reductions across all non-EGU industries in this 
rule generally ranges from approximately $939/ton to $14,595/ton, with 
an overall average of approximately $5,339/ton. See memorandum titled 
``Summary of Final Rule Applicability Criteria and Emissions Limits for 
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the 
Final Emissions Limits, and Estimated Emissions Units, Emissions 
Reductions, and Costs,'' available in the docket.
    Nonetheless, overall the EPA finds that the range of cost-
effectiveness values for non-EGU industries and emissions units 
compares favorably with the values used to evaluate EGUs. As discussed 
in the preceding paragraphs, the representative cost for EGUs to 
retrofit SCR is $11,000/ton. This reflects a range of cost estimates, 
with $20,900/ton reflecting the 90th percentile of units (see section 
V.B.a of this document). The higher end of the estimated average cost 
range for certain non-EGU industrial emissions units is also in that 
range. While specific emissions units may have higher costs associated 
with installing pollution control technologies than other similar unit 
types, this does not in itself undermine the Agency's conclusion that a 
level of emissions control associated with a specific emissions limit 
or control technology is appropriate to require across the linked 
upwind state region, in light of the overall emissions reductions and 
air quality benefits at downwind receptors that those controls are 
projected to deliver.
    We note that the non-EGU control cost estimates in this final rule 
were based on historical actual emissions. This can affect the 
presentation of cost-per-ton values at the unit level, and it would not 
be appropriate to abandon uniform control stringency among like units 
in the covered industries across or within upwind states based on such 
cost differentials.
    The EPA finds it appropriate to require a uniform level of 
emissions control across similar emissions unit types to, among other 
things, prevent two potential outcomes related to shifting production, 
either between units within the same facility or between units at 
different facilities. First, if some units were exempted from control 
requirements because of historically low actual emissions, there is a 
risk that source owners or operators may shift production to these 
specific units, increasing their utilization and resulting in emissions 
increases from these units. Second, if some owners or operators were 
able to avoid the control requirements of the final rule on this basis, 
they could gain a competitive advantage vis-[agrave]-vis other 
facilities within their respective industries. Production could shift 
from units at another facility subject to the control requirements to 
the units that avoided control requirements (and thus avoid costs the 
regulated facility should bear), potentially resulting in emissions 
increases. The effect of such an approach in such circumstances would 
be mere emissions shifting rather than the elimination of significant

[[Page 36747]]

contribution. Finally, as we have explained in prior transport actions, 
the cost-effectiveness figure is not the only factor that the agency 
considers at Step 3, see 86 FR 23073, and if used in isolation to make 
a policy decision without considering other information, could produce 
a result that is inconsistent with the objective of ensuring 
significant contribution is eliminated.\250\
---------------------------------------------------------------------------

    \250\ Nonetheless, recognizing the diverse non-EGU industries 
and emissions units covered in this action and the potential that 
certain individual facilities and emissions units may face extreme 
hardship in meeting the general requirements being finalized in this 
action, the EPA has provided mechanisms in the regulatory 
requirements for industrial sources that provide for some 
flexibility in the emissions limits based on a demonstration of 
technical impossibility or extreme economic hardship. See section 
VI.C of this document.
---------------------------------------------------------------------------

    In addition to our evaluation of cost-effectiveness on a cost per 
ton basis, the EPA's determination at Step 3 for non-EGUs is also 
informed by the overall level of emissions reductions that will be 
achieved across the region and the effect those reductions are 
projected to have on air quality at the downwind receptors (discussed 
more later in this section). We are also influenced by the fact that 
these emissions control strategies for non-EGUs are generally well 
demonstrated to be feasible on many existing units, as established 
through our review of consent decrees, permits, RACT determinations, 
and other data sources. These levels of emissions control have in many 
cases already been required by states with downwind nonattainment areas 
for the 2015 ozone NAAQS.
    The EPA determined that, for 2026, the incremental average air 
quality improvement at receptors relative to the EGU case when SCR 
post-combustion controls were installed was 0.19 ppb when non-EGU 
controls were applied, based on the Step 3 analysis. The total average 
air quality improvement was 0.66 ppb when the non-EGU improvement was 
added to the EGU improvement, meaning that the non-EGU increment 
accounts for about 29 percent of this average air quality improvement. 
In general, the air quality results from non-EGU emissions reductions 
yield additional important downwind benefits to the air quality 
benefits of the EGU strategy. For example, the total ppb improvement 
summed over all of the receptors from EGUs was 7.04 ppb and the non-EGU 
increment adds another 2.82 ppb of improvement bringing the total to 
9.87 (when accounting for rounding). Non-EGUs account for 29 percent of 
this total air quality improvement as well. Further, these figures 
should not be considered in isolation; EPA is not comparing EGU 
strategy effects and non-EGU effects to make a selection between two 
different approaches. Rather, both the selected EGU and non-EGU 
emissions reduction strategies at the cost-effectiveness values 
identified in section V.B and V.C of this document present a 
comprehensive solution to eliminating significant contribution for the 
covered states. The combined effect of the EGU and non-EGU strategies 
is further presented in the following section.

                                         Table V.D.2-2--Air Quality at Receptors in 2026 From Non-EGU Industries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Average DV (ppb)                  Max DV (ppb)
                                                                                         ---------------------------------------------------------------
                                                                                                           EGU SCR/SNCR                    EGU SCR/SNCR
                                                                                                          optimization +                  optimization +
            Monitor ID No.                       State                    County             Baseline      LNB upgrade +     Baseline      LNB upgrade +
                                                                                           (engineering      SCR/SNCR      (engineering      SCR/SNCR
                                                                                             analysis)    retrofit + non-    analysis)    retrofit + non-
                                                                                                                EGU                             EGU
--------------------------------------------------------------------------------------------------------------------------------------------------------
40278011.............................  Arizona.................  Yuma...................           69.87           69.80           71.47           71.40
80590006.............................  Colorado................  Jefferson..............           71.70           71.34           72.30           71.93
80590011.............................  Colorado................  Jefferson..............           72.06           71.57           72.66           72.16
80690011.............................  Colorado................  Larimer................           69.84           69.53           71.04           70.72
90013007.............................  Connecticut.............  Fairfield..............           71.25           70.66           72.06           71.46
90019003.............................  Connecticut.............  Fairfield..............           71.58           71.06           71.78           71.26
350130021............................  New Mexico..............  Dona Ana...............           70.06           69.86           71.36           71.16
350130022............................  New Mexico..............  Dona Ana...............           69.17           68.96           71.77           71.56
350151005............................  New Mexico..............  Eddy...................  ..............  ..............  ..............  ..............
350250008............................  New Mexico..............  Lea....................  ..............  ..............  ..............  ..............
480391004............................  Texas...................  Brazoria...............           69.89           68.50           72.02           70.58
481671034............................  Texas...................  Galveston..............           71.29           69.28           72.51           70.47
482010024............................  Texas...................  Harris.................           74.83           73.39           76.45           74.98
490110004............................  Utah....................  Davis..................           69.90           69.28           72.10           71.46
490353006............................  Utah....................  Salt Lake..............           70.50           69.91           72.10           71.50
490353013............................  Utah....................  Salt Lake..............           71.91           71.40           72.31           71.80
551170006............................  Wisconsin...............  Sheboygan..............           70.83           70.27           71.73           71.17
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Average AQ Change Relative to Base (ppb)............................................  ..............  ..............  ..............            0.66
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Total PPB Change Across All Receptors Relative to Base (ppb)........................  ..............  ..............  ..............            9.87
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ The EPA notes that the design values reflected in Table V.D.-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 Final Rule TSD.
\b\ New Mexico Eddy and Lea monitors have no values in Table V.D.2-2 as EPA does not have calibration factors for these monitors as no contributions
  were calculated for them from the proposal AQ modeling.
\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 VIII of this document provides a more complete picture of the air quality impacts of the final
  rule.


[[Page 36748]]

    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 Final Rule TSD and to the Ozone AQAT included 
in the docket for this rule.
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 air quality effects of the rule and to conduct our over-
control analysis. EPA's evaluation demonstrated air quality improvement 
at the remaining nonattainment or maintenance receptors outside of 
California (see section IV.D of this document for receptor details). 
The EPA estimated that the average air quality improvement at these 
receptors relative to the engineering analytics base case was 0.66 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 non-EGU industries. Table 
V.D.3-1 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 are projected to deliver meaningful downwind air quality 
improvements.

Table V.D.3-1--Change in Air Quality at Receptors in 2026 From Final Rule EGU and Non-EGU Emissions Reductions a
                                                       b c
----------------------------------------------------------------------------------------------------------------
                                                                                   Total PPB       Average PPB
                                                                 Ozone season    change across    change across
                       Sector/technology                           emissions      all downwind     all downwind
                                                                  reductions     receptors \d\      receptors
----------------------------------------------------------------------------------------------------------------
EGU (SCR/SNCR optimization + LNB upgrade).....................          16,282             0.71             0.05
EGU SCR/SNCR Retrofit.........................................          55,672             6.34             0.42
Non-EGU Industries............................................          44,616             2.82             0.19
                                                               -------------------------------------------------
    Total.....................................................  ..............             9.87             0.66
----------------------------------------------------------------------------------------------------------------
Table Notes:
\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 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 associated health and climate benefits are discussed in section VII of
  this document.
\b\ The EPA notes that the design values reflected in Tables V.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 Final Rule TSD.
  Additionally, these emissions reduction values vary slightly from the technology reduction estimates described
  in section V.C of this document, as the values here reflect the sum of the final identified stringency for
  each state (e.g., SCR retrofit potential is not assumed in Alabama, Minnesota, and Wisconsin).
\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 V.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 VIII of this
  document provides a picture of the projected air quality impacts of the final rule using modeling techniques
  that differ from the methodologies employed here.

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. The 
EPA performed air quality analysis using the Ozone AQAT to determine 
whether the emissions reductions for both EGUs and non-EGUs potentially 
create an ``over-control'' scenario. As in prior transport rules 
following the holdings in EME Homer City, overcontrol would be 
established if the record indicated that, for any given state, there is 
an identified, less stringent emissions control approach for that 
state, by which (1) the expected ozone improvements would be sufficient 
to resolve all of the downwind receptor(s) to which that 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) to all receptors. 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. 
Further, 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.\251\
---------------------------------------------------------------------------

    \251\ 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.

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[[Page 36749]]

    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 Transport Policy Analysis Final 
Rule TSD for details on the construction and application of AQAT).
    Similar to our approach in the CSAPR Update and the Revised CSAPR 
Update, our primary overcontrol assessment examines the receptor 
changes from the emissions reductions of the upwind states found linked 
to a receptor. Consistent with prior Rules, EPA also assumed that 
downwind states that are not upwind states in this rule implement 
reductions commensurate with the rule's requirements (this treatment 
applies specifically to Colorado and Connecticut). This configuration 
effectively presents an equitable representation of the effects of the 
rule in that linked upwind states do not shift their responsibility to 
other upwind states linked to different receptors. It also effectively 
resolves any interdependence and ``which state goes first?'' questions. 
Furthermore, the downwind states in which a receptor is located are 
held to a ``fair share'' of emissions reductions--i.e., the same level 
of emissions control stringency that the upwind states must implement.
    The EPA also repeated this analysis using an alternative 
configuration, as described in the Ozone Transport Policy Analysis 
Final Rule TSD. In this configuration, we looked at the combined effect 
of the entire program across all linked upwind states on each receptor 
and did not assume that a downwind state that is not also an upwind 
state makes any additional emissions reductions beyond the baseline in 
the relevant year. This configuration effectively isolates how the rule 
as a whole, and just the rule, will affect air quality and linkages. 
While the first configuration described is, in the Agency's view, the 
more appropriate way to evaluate overcontrol, taken together the 
configurations provide a more robust basis on which to rest our 
conclusions regarding overcontrol. In any case, as further illustrated 
in the Ozone Transport Policy Analysis Final Rule TSD, our analysis 
under both configurations establishes that there is no overcontrol and 
so there is no need to reconcile any difference in results between 
them.
    We also looked at the ordering of increments of emissions reduction 
and have found that it does not matter whether we assume EGU emissions 
controls would be applied first, followed by non-EGU controls, or vice-
versa. For 2023, the question is moot as there are only EGU reductions 
to examine. For 2026, the analysis showed there would be no overcontrol 
either way. In 2026, the EPA's overcontrol analysis (as presented here) 
examined all EGU reductions first and layered in non-EGU reductions in 
the last step of the overcontrol check. However, the EPA also examined 
an alternative ordering scenario where the non-EGU reductions were 
assessed prior to the EGU reductions associated with installation of 
new SCR post-combustion controls (see the Ozone Transport Policy 
Analysis Final Rule TSD for details). This ordering did not impact the 
results of the overcontrol test. The specific results of these analyses 
are presented in the TSD.
    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, is not estimated 
to change the status of any receptors.\252\ Thus, the nonattainment or 
maintenance receptors that the states are linked to remain unresolved. 
Nor do any states' contribution levels drop below the 1 percent of 
NAAQS threshold. Thus, the EPA determined that none of the 23 linked 
states have all of their linkages resolved at the final EGU level of 
control stringency in 2023, and hence, the EPA finds no over-control in 
the final level of stringency.
---------------------------------------------------------------------------

    \252\ For purposes of this rule, the violating monitor receptors 
inform our determinations at Step 1 and 2 by strengthening the 
analytical basis on which we conclude upwind states are linked in 
2023. Because no linkages identified using our air quality modeling 
methodology resolve in 2023 under the selected control stringency, 
it is not necessary to evaluate overcontrol with respect to the 
additional set of violating-monitor receptors.
---------------------------------------------------------------------------

    Based on the air quality baseline modeling for 2026, all receptors 
to which Alabama, Minnesota, and Wisconsin are linked in 2023 are 
projected to be in attainment in 2026. Therefore, no additional 
stringency is finalized for EGUs or non-EGUs in those states beyond the 
2023 level of stringency. For the remaining 20 states, the selected 
control stringency beginning in 2026 includes additional EGU controls 
and the non-EGU emissions reductions.
    The EPA assesses air quality impacts and overcontrol in the year 
2026 in this final rule, even though the rule accommodates the 
potential need for individual facilities (both EGU and non-EGU) to have 
some additional time to come into compliance. The EPA views this 
additional time to be a reflection of need (based on demonstrated 
impossibility) that is justified at Step 4 of the interstate transport 
framework rather than at Step 3. As explained in section VI.A of this 
document, with respect to EGUs, the EPA extends the full implementation 
of the SCR retrofit-based reductions across 2026 and 2027 to 
accommodate any unit-level scheduling challenges. However, we find that 
many sources can meet a three-year installation time and the trading 
program features and the allowance price will incentivize these 
reductions to occur as soon as possible. Similarly, with respect to 
non-EGU industrial sources, the final rule provides limited 
circumstances for individual facilities to seek and to be granted 
extensions of time to install required pollution controls and achieve 
the emissions rates established in this rule based on a showing of 
necessity. Those circumstances where an extension may be warranted for 
any specific facility are unknown at this time and will be evaluated 
through a source-specific application process, where the need for 
extension can be established with source-specific evidence. See section 
VI.C of this document. Further, 2026 is the critical analytic year 
associated with the last full ozone season before the 2027 Serious area 
attainment date and is the year by which significant contribution must 
be eliminated if at all possible. Therefore, for purposes of this 
analysis, the collective state and regional representation of these 
reductions are fully assumed in 2026. The potential ability of both EGU 
and non-EGU sources to have some amount of additional time beyond 2026 
to comply with requirements that we have determined at Step 3 are 
necessary to eliminate significant contribution does not necessitate 
evaluating a later year than 2026 for overcontrol. The stringency of 
the control program does not alter in any year beyond 2026.\253\ By

[[Page 36750]]

fully reflecting all Step 3 emissions reductions in its overcontrol 
test for 2026, EPA ensures that it is not understating the emissions 
impact and benefit when performing the test.
---------------------------------------------------------------------------

    \253\ Thus, we note, this circumstance is different than the 
record on which overcontrol was found in EME Homer City. There, 
CSAPR would have implemented an increase in the emissions control 
stringency of the rule (as reflected in a change in emissions 
control stringency expressed as dollars per ton from $100/ton to 
$500/ton). That change in stringency marked a determination that EPA 
had made at Step 3 regarding the degree of emissions reduction that 
sources needed to achieve beginning in 2014. But in that year, the 
court found EPA's record to reveal that certain states would not 
need to go up to that higher level of stringency because air quality 
problems and/or linkages were already projected to be resolved at 
the lower level of stringency. See 795 F.3d at 128-30. The analogous 
year to 2014 here is 2026. The stringency level of this control 
program does not change post-2026. Nor do we think individual 
sources should gain the benefit of delaying emissions reductions 
simply in the hopes that they could show those reductions would be 
overcontrol; each source must be held to the elimination of its 
portion of significant contribution. Necessity may demand some 
additional amount of time for compliance, but equity demands that 
individual sources not gain an untoward advantage from delay and 
reliance on other sources' timelier compliance.
---------------------------------------------------------------------------

    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 is 
estimated to change the status of three receptors to attainment or 
maintenance in 2026. Brazoria County, Texas (Monitor ID 480391004); and 
Galveston County, Texas (Monitor ID 481671034), are estimated to come 
into attainment. We observe that one of the Fairfield, Connecticut, 
receptors (Monitor ID 090013007) is estimated to go from nonattainment 
to maintenance (when EGU emissions reductions with SCR are applied, 
prior to the application of the non-EGU emissions reductions). This 
receptor is expected to remain in maintenance even after the 
application of the non-EGU emissions reductions. Based on these data, 
EPA finds that all linked states except Arkansas, Mississippi, and 
Oklahoma are projected to 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 states. Arkansas, 
Mississippi, and Oklahoma are linked to at least one of the two Texas 
receptors that are projected to come into attainment with the full 
implementation of the control strategy at Step 3. However, these two 
Texas receptors are expected to remain as maintenance-only receptors 
prior to the final increment of reductions assessed (the addition of 
the non-EGU reductions), so EPA concludes that imposition of the 
incremental non-EGU level is appropriate to avoid under-control as to 
these states and does not constitute overcontrol.\254\
---------------------------------------------------------------------------

    \254\ Even with full implementation of the rule, these two 
receptors are only projected to come into attainment by a relatively 
small degree, and no policy option is ascertained in the record by 
which attainment could be achieved to an even lesser degree. 
Nonetheless, the EPA further evaluated whether there were any 
overcontrol concerns through sensitivity analyses. Under all 
scenarios, the EPA finds there is no overcontrol. See the Ozone 
Transport Policy Analysis Final Rule TSD for more discussion and 
analysis.
---------------------------------------------------------------------------

    Next, the EPA evaluated the potential for over-control with respect 
to the 1 percent of the NAAQS threshold applied in this final 
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 23 linked states in 2023 or 20 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 are projected to continue 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. EPA notes that 
in 2026, for Oklahoma, when the incremental level of stringency 
associated with the non-EGU control strategy is applied, Oklahoma's 
contribution to Galveston County Texas is expected to drop below the 1 
percent threshold (at the same time that the receptor has its 
maintenance problems resolved). EPA concludes that this does not 
constitute overcontrol because both the receptor and the contribution 
are estimated to remain above the maintenance level and linkage 
threshold at the prior level of stringency and, thus, since otherwise 
justified at Step 3, the full stringency for 2026 is appropriate to 
avoid under-control. For more information about this assessment, refer 
to the Ozone Transport Policy Analysis Final Rule TSD and the Ozone 
AQAT.
    Therefore, EPA finds that all of the selected EGU and non-EGU 
NOX reduction strategies selected in EPA's Step 3 analysis 
can be applied to all states linked in 2026 to eliminate significant 
contribution to nonattainment and interference with maintenance of the 
2015 ozone NAAQS without introducing an overcontrol problem based on 
the present record. 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.
    The determination that the stringency of this action does not 
constitute overcontrol for any linked state is further reinforced by 
EPA's observation in section III.A of this document regarding the 
nature of the ozone problem. Ozone levels are known to vary, at times 
dramatically, from year to year. Future ozone concentrations and the 
formation of ground level ozone may also be impacted by factors in 
future years that the EPA cannot fully account for at present. For 
example, changes to meteorological conditions could affect future ozone 
levels. Climate change could also contribute to higher than anticipated 
ozone levels in future years through wildfires and heat waves, which 
can contribute directly and indirectly to higher levels of ozone. Any 
modeling projection can be characterized as having some uncertainty, 
and that is not a sufficient reason to ignore modeling results. 
However, in the context of the overcontrol test, the question is 
whether it is clear according to particularized evidence that there is 
no need for the emissions reductions in question. See EME Homer City, 
572 U.S. at 523 (``[A] degree of imprecision is inevitable in tackling 
the problem of interstate air pollution. Slight changes in wind 
patterns or energy consumption, for example, may vary downwind air 
quality in ways EPA might not have anticipated.''). Under this 
standard, the degree of attainment that is projected to occur under the 
rule in relation to the Texas receptors discussed above is not so large 
or certain to occur that it would be appropriate to attempt to devise a 
less stringent emissions control strategy for the relevant linked 
states as a result, particularly in light of the fact that at the 
penultimate stringency level the receptors are not resolved.
    It is also possible that ozone-precursor emissions from certain 
sources may decline beyond what we currently project in this rule. For 
example, the IRA may result in reductions in fossil-fuel fired 
generation, which should in turn result in lower NOX 
emissions during the ozone season.\255\ We have

[[Page 36751]]

assessed this scenario to ensure our overcontrol conclusions are robust 
even if the IRA has those effects. As discussed in the Regulatory 
Impact Analysis, the EPA conducted additional modeling of the final 
policy scenario (inclusive of economically efficient methods of 
compliance available within the Step 4 implementation programs) using 
its IPM tool. The EPA observes that the differences in estimated costs 
and emissions reductions in the IRA sensitivity (presented in Appendix 
4A of the RIA) suggests that there would also be differences in 
estimated health and climate benefits under that scenario, although the 
Agency did not have time under this rulemaking schedule to quantify 
those differences. The EPA also used AQAT to conduct an additional EGU 
modeling sensitivity reflecting the IRA. Both the IPM sensitivity and 
the corresponding AQAT assessment of the IRA scenarios demonstrated no 
overcontrol as every state linkage to a downwind problematic receptor 
persisted in the penultimate level of stringency when EPA performed its 
Step 3 evaluation--even when the impacts of the IRA are incorporated. 
This further affirmed EPA's conclusion of no overcontrol concerns at 
the stringency level of the final rule. This overcontrol sensitivity is 
further discussed in the Ozone Transport Policy Analysis Final Rule 
TSD, Appendix K.
---------------------------------------------------------------------------

    \255\ As discussed in section IV.C.2.b, there are also potential 
ways in which the IRA may not necessarily result in reductions in 
NOX emissions from EGUs.
---------------------------------------------------------------------------

    In light of the mandate of the CAA to protect the public health and 
environment through the elimination of significant contribution under 
the Good Neighbor Provision for the 2015 ozone NAAQS, nothing in the 
present record establishes on an as-applied, particularized basis that 
this rule will result in an unnecessary degree of control of upwind-
state emissions.
    Comment: Many commenters alleged that the rule overcontrols 
emissions by more than necessary to eliminate significant contribution 
for the 2015 ozone NAAQS, on the basis that the emissions reductions 
are unnecessary or are unnecessarily stringent.
    Response: As discussed earlier in this section, EPA has analyzed 
whether this rule ``overcontrols'' emissions and has found based on a 
robust, multi-faceted analysis, that it does not. In particular, EPA 
has not identified a lesser-stringency emissions control strategy for 
any state that would either fully resolve the air quality problems at a 
downwind receptor location or resolve that upwind state's linkage to a 
level below the 1 percent of NAAQS contribution threshold. No commenter 
has provided a particularized, as-applied analysis demonstrating that 
EPA's emissions control strategy will actually result in any 
overcontrol of emissions in the manner the EPA or courts have 
understood that term, and overcontrol allegations must be proven 
through particularized, as-applied challenges. See EME Homer City, 795 
F.3d at 127; see also Wisconsin, 938 F.3d at 325 (``[T]he way to 
contest instances of over-control is not through generalized claims 
that EPA's methodology would lead to over-control, but rather through a 
`particularized, as-applied challenge.' '' Accordingly, as we did when 
presented with similar arguments in EME Homer III, we reject Industry 
Petitioners' arguments because they do no more than speculate that 
aspects of `EPA's methodology could lead to over-control of upwind 
States.' '') (cleaned up) (citing EME Homer City, 795 F.3d at 136-137).
    Comment: For 2 of the 20 states linked in 2026, Arkansas and 
Mississippi, the last downwind receptor to which these two states are 
linked (i.e., Brazoria County, Texas) was estimated to achieve 
attainment and maintenance after full application of EGU reductions and 
Tier 1 non-EGU reductions at proposal. Commenters noted that this 
suggested application of the estimated non-EGU, and/or some EGU, 
emissions reductions constituted over-control for these states.
    Response: EPA notes that at proposal, this downwind receptor only 
resolved by a small margin after the application of all EGU and Tier 1 
non-EGU emissions reductions. As explained earlier in this section, the 
final rule air quality modeling shows that the receptors to which these 
states are linked do not resolve upon full implementation of the 
identified EGU reductions by themselves, and only reach attainment by a 
small degree following the additional reductions from the non-EGU 
control strategy.\256\ If the EPA were to select the control stringency 
of this penultimate step, both upwind-state contribution and downwind-
state air quality receptors would persist while the cost-effective 
emissions reductions that were identified to eliminate significant 
contribution remain available but un-implemented. This would constitute 
under-control. Consequently, as described, the EPA views the control 
stringency required of these states in this final rule as not 
constituting over-control and appropriate to eliminate significant 
contribution to nonattainment and interference with maintenance of this 
NAAQS in line with our Step 3 determinations for all other states. See 
the Ozone Transport Policy Analysis Final Rule TSD section C.3 for 
discussion and analysis regarding overcontrol for states solely linked 
to one or both of these receptors.
---------------------------------------------------------------------------

    \256\ Because in the final record we do not identify cost, air 
quality, and emission reduction factors that sufficiently 
differentiate either source-type or emissions control strategy among 
the Tier 1 and Tier 2 industries identified at proposal, we combined 
the non-EGU industries and emissions reductions into one group, and 
we are finalizing requirements for all non-EGU industries and most 
emissions unit types identified at proposal. In light of the small 
degree to which the relevant receptors reach attainment and the 
multi-faceted assessment of overcontrol we have undertaken, the 
overcontrol assessment with respect to non-EGUs in the final rule is 
sufficient to establish that there is no overcontrol.
---------------------------------------------------------------------------

    Comment: Commenters raised a variety of arguments that the 
enhancements to the EGU trading program in this action will result in 
overcontrol of power plant emissions. They alleged that dynamic 
budgeting would cause the budget to continually decrease even after 
significant contribution is eliminated. They similarly argue that 
annual emissions bank recalibration and the emissions backstop 
emissions rate have not been shown to be justified to eliminate 
significant contribution.
    Response: This final rule's determination regarding the appropriate 
level of control stringency for EGUs finds that the amounts of 
NOX emissions reduction achieved through these strategies at 
EGUs are appropriate and cost-justified under the Step 3 multifactor 
analysis. These determinations are associated with particular emissions 
control technologies and strategies as detailed in sections V.B.1 and 
V.C.1 above. It is the implementation of those strategies at the 
covered EGU sources and the air quality effects of those strategies 
(coupled with non-EGUs) in the relevant analytic year of 2026 on which 
we base our determination of significant contribution at Step 3. This 
includes the evaluation of whether there is overcontrol, which is also 
conducted for the 2026 analytic year as explained above. As explained 
below, we disagree that the enhancements to the trading program at Step 
4 implicate the need for further overcontrol analysis. These 
enhancements operate together to ensure the trading program continues 
to maintain the Step 3 emissions control stringency over time. These 
enhancements reflect lessons learned through EPA's experience with 
prior trading programs implemented under the good neighbor provision. 
None of commenters' arguments that these enhancements result in 
overcontrol are persuasive.
    Commenters contend that these enhancements to the trading program 
go

[[Page 36752]]

beyond a mass-based budget approach as applied in CSAPR. Because these 
improvements in the program result in a continuing incentive for each 
covered EGU source to maintain the pollution control performance the 
EPA found appropriate to eliminate significant contribution at Step 3, 
commenters believe these enhancements must necessarily result in 
prohibited overcontrol. These arguments appear to be premised on the 
assumption that overall emissions may later decline to such a point 
that there is no longer a linkage between a particular state and any 
downwind receptors for reasons other than the requirements of this 
rule.
    As an initial matter, no commenter has provided an empirical 
analysis demonstrating that the control stringency identified at Step 3 
to eliminate significant contribution would actually result in any 
overcontrol. The case law is clear that over-control allegations must 
be proven through particularized, as-applied challenges. See prior 
response to comments. More importantly here, the Group 3 trading 
program enhancements do not impose increased stringency in years after 
2030 and do not force emissions to continually be reduced to ever lower 
levels. They are only designed to incentivize the implementation of the 
Step 3 emissions control stringency that eliminates significant 
contribution. The circumstances that could potentially cause a receptor 
or linkage to resolve at some point in the future after 2026 are not 
circumstances that are within the power of this rule to control. Nor 
would those circumstances present a justification as to why upwind 
sources should no longer be obligated to eliminate their own 
significant contribution. Wisconsin, 938 F.3d at 324-25 (rejecting 
overcontrol arguments premised on attributing air quality problems to 
other emissions).
    Further, the EPA is not constrained by the statute to only 
implement good neighbor obligations through fixed, unchanging, mass-
based emissions budgets. See section III.B.1 of this document. The EPA 
has defined the ``amount'' of emissions that must be prohibited to 
eliminate significant contribution in this action based on a series of 
determinations of which emissions control strategies, for certain 
identified EGU and non-EGU sources, are appropriate applying the Step 3 
multifactor analysis. Notably, the non-EGU industrial source emissions 
reductions in this action are not being achieved at Step 4 through 
mass-based emissions trading, nor are they required to be by any 
provision of the CAA. See section III.B.1.
    As explained in sections III.B.1.d and VI.B.1 of this document, the 
EPA finds good reason based on its experience with trading programs 
that using fixed, mass-based, ozone-season wide budgets does not 
necessarily ensure the elimination of significant contribution over the 
entire region of linked states or throughout each ozone season. Even in 
the original CSAPR rulemaking, which promulgated only fixed, mass-based 
budgets, such outcomes were never the EPA's intention to allow. See, 
e.g., 76 FR 48256-57 (``[I]t would be inappropriate for a state linked 
to downwind nonattainment or maintenance areas to stop operating 
existing pollution control equipment (which would increase their 
emissions and contribution).''). Despite the EPA's expectations in 
CSAPR, the experience of the Agency since that time establishes a real 
risk of ``under-control'' if the existing trading framework is not 
enhanced. See EME Homer City, 572 U.S. at 523 (``[T]he Agency also has 
a statutory obligation to avoid `under-control,' i.e., to maximize 
achievement of attainment downwind.'').
    Further, the EPA has already once adjusted its historical approach 
to better account for known, upcoming changes in the EGU fleet to 
ensure mass-based emissions budgets adequately incentivize the control 
strategy determined at Step 3. This adjustment was introduced in the 
Revised CSAPR Update. See 82 FR 23121-22. The EPA now believes it is 
appropriate to ensure in a more comprehensive manner, and in 
perpetuity, that a mass-based emissions-trading framework incentivizes 
continuing implementation of the Step 3 control strategies to ensure 
significant contribution is eliminated in all upwind states and remains 
so. This is fully analogous in material respect to an approach to 
implementation at Step 4 that relies on application of unit-specific 
emissions limitations, which under the Act would typically apply in 
perpetuity and may only be modified through a future SIP- or FIP-
revision rulemaking process. See CAA section 110(i) prohibiting 
modifications to implementation plan requirements except by enumerated 
processes. The availability of unit-specific emissions rates as a means 
to eliminate significant contribution is discussed in further detail in 
section III.B.1 of this document. The EPA also explained this in the 
proposal. See 87 FR 20095-96.
    Further, these enhancements are directly related to assisting 
downwind areas specifically with the goal of attaining and maintaining 
the 2015 8-hour ozone NAAQS. In this respect, they are not 
``unnecessary'' or ``unrelated'' to carrying out the mandates of CAA 
section 110(a)(2)(D)(i)(I). Taking measures to ensure that each upwind 
source covered by an emissions trading program is adequately 
incentivized to eliminate excessive emissions (as found at Step 3) 
throughout the entirety of each ozone season is entirely appropriate in 
light of the nature of the ozone problem. Ozone exceedances recur on 
varying days throughout the summertime ozone season, and it is not 
possible to predict in advance which specific days will have high 
ozone. Further, impacts to public health and the environment from ozone 
can occur through short-term exposure (e.g., over a course of hours, 
i.e., on a daily basis). The 2015 ozone NAAQS is expressed as an 8-hour 
average, and only a small number of days in excess of the ozone NAAQS 
can cause a downwind area to be in nonattainment. Thus, even a small 
number of exceedances can result in continuing and/or increased 
regulatory burdens on the downwind jurisdiction. Taking these 
considerations into account, it is evident that a fixed, mass-based 
emissions program that does not adequately incentivize emissions 
reductions commensurate with our Step 3 determinations on each day of 
every ozone season going forward does not provide a sufficient 
guarantee that the emissions that significantly contribute on those 
particular days and at particular receptor locations when ozone levels 
are at risk of exceeding the NAAQS have been eliminated. See section 
V.B.1.a and VI.B of this document for more discussion of data 
observations regarding SCR optimization.
    These enhancements are also consistent with the general policies 
and principles EPA has long applied in implementing the NAAQS through 
the SIP/FIP framework of section 110. Emissions control measures relied 
on to meet CAA requirements must be permanent and enforceable and 
included in the implementation plan itself. See, e.g., Montana Sulfur & 
Chem. Co. v. EPA, 666 F.3d 1174, 1196 (9th Cir. 2012); 40 CFR 
51.112(a). In the General Preamble laying out EPA's plans for 
implementing the 1990 CAA Amendments, the EPA identified a core 
``principle'' that control strategies should be ``accountable.'' ``This 
means, for example, that source-specific limits should be permanent and 
must reflect the assumptions used in the SIP demonstrations.'' 57 FR 
13498, 13568 (April 16, 1992). EPA went on, ``The principles of 
quantification, enforceability, replicability, and

[[Page 36753]]

accountability apply to all SIPs and control strategies, including 
those involving emissions trading, marketable permits and allowances.'' 
Id. EPA also explained that its ``emissions trading policy provides 
that only trades producing reductions that are surplus, enforceable, 
permanent, and quantifiable can get credit and be banked or used in an 
emissions trade.'' Id. These principles follow from the language of the 
Act, including CAA section 110(a)(2), 107(d)(3)(E)(iii), 110(i), and 
110(l). These provisions and principles further underscore the 
importance of ensuring that the emissions reductions the EPA has found 
necessary to eliminate significant contribution are in fact implemented 
on a consistent and permanent basis even within the context of an 
emissions trading program.
    The EPA disagrees that the budget adjustments that would occur over 
time under this final rule (for example, the annual dynamic-budget 
adjustment) must be reassessed each time they occur through notice and 
comment rulemaking under CAA section 307(d). This would serve no 
purpose. The formulas that the EPA will apply to adjust the budgets and 
allowance bank are set in this final rule and are intended to maintain, 
not increase (or decrease), program stringency. While the EPA intends 
to provide an opportunity for stakeholders to review and propose 
corrections to its data as it implements the established budget 
formulas, no larger reassessment of the emissions control program is 
needed on an ongoing basis, because, again, that program is simply 
calibrated to ensure that emissions reductions commensurate with the 
determination of ``significance'' in Step 3 continue to be obtained 
over the long term. As described earlier, these trading program 
provisions are analogous to, or mimic, the effect of unit-specific 
emissions limitations that apply in perpetuity.\257\
---------------------------------------------------------------------------

    \257\ We note further that because all of the trading program 
provisions, including the dynamic budget-setting provisions and 
process, are established by this final FIP rulemaking, the 
ministerial future-year budget adjustment process complies with the 
CAA section 110(i) prohibition on modification of implementation 
plan requirements except by enumerated process.
---------------------------------------------------------------------------

    Commenters also confuse the ``amount'' of emissions that must be 
eliminated under CAA section 110(a)(2)(D)(i)(I) as being synonymous 
with a fixed, mass-based budget that reflects the residual emissions 
allowed following the elimination of significant contribution. However, 
EPA views the ``amount'' to be eliminated as those emissions that are 
in excess of the cost-effective emissions control strategies identified 
in Step 3. This is further explained in section III.B.1 of this 
document.
    Thus, this rule is in compliance with the overcontrol principles 
that the D.C. Circuit applied on remand in EME Homer City to find 
certain instances of overcontrol in CSAPR's emissions control 
strategies. The D.C. Circuit found that EPA had imposed more stringent 
emissions-control strategies for certain states than were necessary to 
resolve all of those states' linkages. 795 F.3d at 128-30. 
Specifically, for sulfur dioxide, the court found certain receptors 
would reach attainment if all linked upwind states had implemented 
``cost controls'' at $100/ton or $400/ton, rather than EPA's selected 
stringency level of $500/ton. Similarly, for ozone season 
NOX, the court found that receptors were projected to attain 
the NAAQS at stringencies below $500/ton. The court's focus was on the 
stringency of the emissions control obligations as determined through 
the application of cost thresholds at Step 3 of the analysis. The court 
did not hold that EPA may only use fixed, mass-based budgets to 
implement those reductions. The court did not hold that EPA must permit 
individual polluting sources to be allowed to increase their emissions 
at some point in the future. The court did not hold that EPA's good 
neighbor FIPs must, effectively, contain termination clauses, such that 
they cease to ensure the implementation of the control stringency 
determined as necessary at Step 3, the moment a downwind receptor 
reaches attainment. Indeed, such a rule would contravene the statute's 
clear, forward-looking directive that EPA must also eliminate upwind 
emissions that interfere with maintenance of the NAAQS; see North 
Carolina, 531 F.3d at 908-911; Wisconsin, 938 F.3d at 325-26.
    The EME Homer City court on remand in fact rejected various 
arguments that other aspects of EPA's emissions control strategy in 
CSAPR resulted in overcontrol, holding that EPA had properly given 
effect to the interfere with maintenance prong, and noting that 
petitioners failed to make out proven, as-applied demonstrations of 
overcontrol:

    At bottom, each of those claims is an argument that EPA's 
methodology could lead to over-control of upwind States that are 
found to interfere with maintenance at a downwind location. That 
could prove to be correct in certain locations. But the Supreme 
Court made clear in EME Homer that the way to contest instances of 
over-control is not through generalized claims that EPA's 
methodology would lead to over-control, but rather through a 
``particularized, as-applied challenge.'' EME Homer, 134 S. Ct. at 
1609, slip op. at 31. And petitioners do not point to any actual 
such instances of over-control at downwind locations.

795 F.3d at 137. The court went on to observe, ``EPA may only limit 
emissions `by just enough to permit an already-attaining State to 
maintain satisfactory air quality.' If States have been forced to 
reduce emissions beyond that point, affected parties will have 
meritorious as-applied challenges.'' Id. (quoting 572 U.S. at 521-22). 
But this too was not a holding that EPA may not ensure effective and 
permanent implementation of an emissions control stringency that EPA 
has found warranted under CAA section 110(a)(2)(D)(i)(I). Such an 
approach is available through the more conventional CAA practice of 
setting unit-specific emissions limitations that would apply on a 
permanent and enforceable basis. See CAA sections 110(a)(2) and 302(y) 
(providing for SIPs and FIPs to include ``enforceable emissions 
limitations'' in addition to economic incentive measures like trading 
programs).\258\ This is in fact how EPA intends to ensure significant 
contribution is eliminated from non-EGU industrial sources for which a 
mass-based trading regime is, at least at the present time, unworkable 
(see section VI.C of this document). And EPA has provided for the 
elimination of significant contribution through source-specific 
emissions limitations in prior transport actions as well, so this 
position is not novel. See section III.B of this document.
---------------------------------------------------------------------------

    \258\ ``Emissions limitation'' is in turn defined at CAA section 
302(k) as a ``requirement . . . which limits the quantity, rate, or 
concentration of emissions of air pollutants on a continuous basis. 
. . .''
---------------------------------------------------------------------------

    Nonetheless, EPA recognizes that under the Act, both FIPs and SIPs 
may be revised, and states may replace FIPs with SIPs if EPA approves 
them. Any such revision must be evaluated to ensure no applicable CAA 
requirements are interfered with. See, e.g., Indiana v. EPA, 796 F.3d 
803 (7th Cir. 2015). For example, states may be able to demonstrate in 
the future that through some other permanent and enforceable methods of 
emissions reduction that they have adopted into their SIP, they will be 
able to achieve a similar emissions control stringency with different 
emissions reduction requirements imposed on different sources as 
compared to the FIPs finalized in this action. See section VI.D of this 
document.
    Therefore, commenters' contentions that EPA's trading program 
enhancements result in prohibited

[[Page 36754]]

overcontrol are not proven through as-applied, particularized 
challenges, and they are premised on an incorrect understanding of the 
CAA and the relevant case law. The Agency rejects the contention that 
it must somehow provide in the present FIP action for a relaxation in 
the stringency of the Step 4 implementation program and thus allow for 
the recurrence of pollution that we have found here, in this action, 
significantly contributes to downwind ozone nonattainment and 
maintenance problems.

VI. Implementation of Emissions Reductions

A. NOX Reduction Implementation Schedule

    This action will ensure that emissions reductions necessary to 
eliminate significant contribution will be achieved ``as expeditiously 
as practicable'' and no later than the downwind attainment dates except 
where compliance by those dates is not possible. See CAA section 
181(a); Wisconsin, 938 F.3d at 318-20. The timing of this action will 
provide for all possible emissions reductions to go into effect 
beginning in the 2023 ozone season for the covered states, 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 will take effect as 
expeditiously as practicable. Emissions reductions commensurate with 
SCR mitigation measures for EGUs will start in 2026 and be fully 
implemented by 2027. Emissions reductions through the mitigation 
measures for industrial sources will generally go into effect in 2026; 
however, as explained in section VI.C of this document, we have 
provided for case-by-case extensions of up to one year based on a 
demonstration of necessity (with the potential for up to an additional 
two years based on a further demonstration). The full suite of 
emissions reductions is generally anticipated to take effect by the 
2027 ozone season, which is aligned with the August 3, 2027, attainment 
date for areas classified as Serious nonattainment under the 2015 ozone 
NAAQS. This rule constitutes a full remedy for interstate transport for 
the 2015 ozone NAAQS for the states covered; the EPA does not 
anticipate further rulemaking to address good neighbor obligations 
under this NAAQS will be required for these states with the 
finalization of this rule.
    EPA's determinations regarding the timing of this rule are informed 
by and in compliance with several recent court decisions. The D.C. 
Circuit has reiterated several times 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.\259\ 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.\260\ 
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.\261\ 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.\262\ 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.'' \263\
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    \259\ 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).
    \260\ North Carolina, 531 F.3d at 911-913.
    \261\ Wisconsin, 938 F. 3d at 303, 3018-20.
    \262\ 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).
    \263\ 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 rulemaking cover the 2023, 2024, and 2025 ozone seasons. This 
is the period in which some reductions will be available, but the 
portion of full remedy reductions related to post combustion control 
installation identified in sections V.B through V.D of this document 
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 V.B through V.D of this document 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. 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 VI.B.7 of this 
document, unit-specific backstop daily emissions rates are applied to 
coal units with existing SCR at a level consistent with operating that 
control. The EPA believes that implementing these emissions reductions 
through state emissions budgets starting in 2023 while imposing the 
unit-specific backstop emissions rates in 2024 achieves the necessary 
environmental

[[Page 36755]]

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 22 states for which emissions reduction 
requirements for EGUs are established under this 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).\264\ The EPA 
is applying the same timing assumption regarding combustion control 
upgrades for this rulemaking. Given the same relationship here between 
the date of final action and the year one ozone season, the EPA is not 
assuming the implementation of any additional combustion control 
upgrades in state emissions budgets until year two (i.e., the 2024 
ozone season). Any identified combustion control upgrade emissions 
reductions are reflected beginning in the 2024 ozone-season budgets for 
all covered states. For the 12 states covered under the Revised CSAPR 
Update, any identified emissions reduction potential from combustion 
control upgrade is included and reflected in those state budgets 
beginning in 2024--which means EGUs in those states have even more time 
than the 14 months between finalization of this rule and the 2024 ozone 
season if they started any planning or installation earlier in response 
to the Revised CSAPR Update.
---------------------------------------------------------------------------

    \264\ 86 FR 23093.
---------------------------------------------------------------------------

2. 2026 and Later Years: EGU and Stationary Industrial Source 
NOX Reductions Beginning in 2026
    The EPA finds that it is not possible to implement all necessary 
emissions controls across all of the affected EGU and non-EGU sources 
by the August 3, 2024, Moderate area attainment date. In accordance 
with the good neighbor provision and the downwind attainment schedule 
under CAA section 181 for the 2015 ozone NAAQS, the EPA is aligning 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. The 2026 ozone season is the last full ozone season that 
precedes the August 3, 2027, Serious area attainment date for the 2015 
ozone NAAQS.\265\ The EPA proposed to require compliance with all of 
the remaining EGU and non-EGU control requirements beginning in the 
2026 ozone season. The EPA continues to find 2026 to be the relevant 
analytic year for purposes of its Step 3 analysis, including its 
analysis of overcontrol, as discussed in section V.D.4 of this 
document. However, many commenters argued that full implementation of 
the EGU and industrial source control strategies is not feasible for 
every source by the 2026 ozone season. The EPA addresses these 
technical comments specifically in sections V.B and VI.C of this 
document. The EPA also commissioned a study to develop a better 
understanding of the time needed for installation of emissions controls 
for the industrial sector units covered in this rule, which is included 
in the docket and discussed in section VI.A.2.b of this document. While 
the EPA does not agree with all of the commenters' assertions regarding 
the time they claim is needed for control installation, in other 
respects the concerns raised were sufficient to justify some 
adjustments to the compliance schedule for the final rule. We have 
provided for the emissions reductions commensurate with assumed EGU 
post-combustion emissions control retrofits to be phased in over the 
2026 and 2027 ozone season emissions budgets, and we have provided a 
process in the final regulations for individual non-EGU industrial 
sources to seek limited compliance extensions extending no later than 
2029 based on a case-by-case demonstration of necessity. This 
compliance schedule delivers substantial emissions reductions in the 
2026 and 2027 ozone seasons and before the 2027 Serious area attainment 
date, and it only allows compliance extensions beyond that attainment 
date based on a rigorous, source-specific demonstration of need for the 
additional time.\266\
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    \265\ 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).
    \266\ While we generally use the term ``necessity'' to describe 
the showing that non-EGU facilities must meet in seeking compliance 
extensions, the elements for this showing are designed to allow the 
EPA to make a judgment that comports with the standard of 
``impossibility'' established in case law such as Wisconsin. In 
other words, the ``necessity'' for additional time is effectively a 
showing by the source that it would be ``impossible'' for it to meet 
the compliance deadline.
---------------------------------------------------------------------------

    The timing of this final rule provides three to four years for EGU 
and non-EGU sources to install whatever controls they deem suitable to 
comply with required emissions reductions by the start of the 2026 and 
2027 ozone seasons. In addition, the publication of the proposal 
provided roughly an additional year of notice to these source owners 
and operators that they should begin engineering and financial planning 
(steps that can be taken prior to any capital investment) 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 
reasonable and achievable. A 3-year period for installation of 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 three 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.\267\ Thus, in the 
provision that allows for direct Federal regulation of sources 
violating the good neighbor provision, Congress established three years 
as the maximum amount of time available from a final rule to when 
emissions reductions need to be achieved at the relevant source or 
group of sources. Because this action is not taken under CAA section 
126(c), the mandatory timeframe for implementation of emissions 
controls

[[Page 36756]]

under that provision is not directly applicable, but it is informative.
---------------------------------------------------------------------------

    \267\ CAA 110(a)(2)(D)(i) and 126(c).
---------------------------------------------------------------------------

    In response to arguments from sources that more time than has been 
provided in the final rule is necessary, this provision strongly 
indicates that allowing time beyond a three-year period must be based 
on a substantial showing of impossibility. Our analysis based on 
comments and considering additional information is that the additional 
time we have provided in the final rule is both justified and 
sufficient in light of the statutory objective of expeditious 
compliance.
    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.\268\ 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 three years after the deadline for 
submitting RACT SIP revisions.\269\ 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.\270\ 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.\271\ Nonattainment areas for the 2015 
ozone NAAQS that were reclassified to Moderate nonattainment in October 
2022 face this same regulatory schedule, meaning that their sources are 
required to implement RACT controls in 2023. With the exception of the 
Uinta Basin, which is not an identified receptor in this action, no 
Marginal nonattainment area met the conditions of CAA section 181(a)(5) 
to obtain a one-year extension of the Moderate area attainment date. 87 
FR 60899 (Oct. 7, 2022). Thus, all Marginal areas (other than Uinta) 
that failed to attain have been reclassified to Moderate. Id. In the 
October 2022 final rulemaking EPA made determinations that certain 
Marginal areas failed to attain by the attainment date, reclassified 
those areas to Moderate, and established SIP submission deadlines and 
RACM and RACT implementation deadlines. EPA set the attainment SIP 
submission deadlines for the bumped up Moderate areas to be January 1, 
2023. See 87 FR 60897, 60900. The implementation deadline for RACM and 
RACT is also January 1, 2023. Id.
---------------------------------------------------------------------------

    \268\ 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 SIP submission deadline under 40 CFR 51.1112(a)(2)) 
and 51.1312(a)(2)(i), respectively).
    \269\ 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 40 CFR 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.
    \270\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP 
revisions no later than 24 months after the effective date of 
designation).
    \271\ 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.
---------------------------------------------------------------------------

    The EPA notes that the types and sizes of the EGU and non-EGU 
sources that the EPA includes in this rule, as well as the types of 
emissions control technologies on which the EPA bases the emissions 
limitations that would take effect for the 2026 and 2027 ozone seasons, 
generally are 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.\272\ 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 three years 
is an outer limit on the time that should be given sources to come into 
compliance where possible. In light of the January 1, 2023, deadline 
for implementation of RACT in Moderate nonattainment areas, the EPA 
finds that a May 1, 2026 deadline for full implementation of the 
emissions control requirements in this final rule would generally 
provide adequate time for any individual source to install the 
necessary controls, barring the circumstances of necessity discussed 
further in this section.
---------------------------------------------------------------------------

    \272\ See the Final 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. CAA 
section 112(i)(3)(B) 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 (7) provide for limited 
compliance extensions where other conditions are met.\273\ 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 where 
possible. As discussed further in section VI.A.2.b of this document, 
the process for obtaining a compliance extension for industrial sources 
in this rule is generally modeled on 40 CFR 63.6(i)(3), which 
implements

[[Page 36757]]

the extension provision for existing sources under CAA section 
112(i)(3)(B).
---------------------------------------------------------------------------

    \273\ See, e.g., CAA section 112(i)(4), which provides for 
limited compliance extensions granted by the President based on 
national security interests.
---------------------------------------------------------------------------

    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 an 
upper bound of time allowable (barring instances of impossibility) for 
existing stationary sources to install or begin the installation of 
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,\274\ the implementation of good neighbor obligations for these 
NAAQS is already delayed, and the sources subject to 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 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 V.B.1.b of this document 
beginning in the 2026 ozone season (with full implementation by the 
2027 ozone season for EGUs, and the availability of source-specific 
extensions based on a demonstration of necessity for non-EGUs).
---------------------------------------------------------------------------

    \274\ 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).
---------------------------------------------------------------------------

    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 under CAA section 110(c) to promulgate a 
FIP.\275\ 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.'' \276\
---------------------------------------------------------------------------

    \275\ 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.
    \276\ 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 in the following sub-sections, the EPA 
finds 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),\277\ and, for certain sources, 
may not be possible by the 2026 ozone season or even the August 3, 
2027, Serious area attainment date. While the EPA's technical analysis 
demonstrates that for any individual source, control installation could 
be accomplished by the start of the 2026 ozone season, in light of the 
scope of this rule coupled with current information on the present 
economic capacity of sources, control-installation vendors, and 
associated markets for labor and material, it is the EPA's judgment 
that a three-year timeframe is not possible for all sources subject to 
this rule collectively to come into compliance. Therefore, additional 
time beyond 2026 will be allowed for certain facilities in recognition 
of these constraints on the processes needed for installation of 
controls across all of the covered sources.
---------------------------------------------------------------------------

    \277\ 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 V.B through V.D of this document, 
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 36-48 months 
in this final rule. This amount of time allows for all necessary 
procurement, permitting, and installation milestones across multiple 
units in the covered region. Therefore, the EPA finds that these 
emissions reductions are not available any earlier than the 2026 
compliance period. Starting in 2026, state emissions budgets will 
reflect full implementation of assumed SNCR mitigation measures and 
implementation of half the emissions reduction potential identified for 
assumed SCR mitigation measures. For each year in 2027 and beyond, 
state emissions budgets include all of the emissions 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 
\278\), nearly 19 GW of SCR 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 within 
a 36-month period.
---------------------------------------------------------------------------

    \278\ 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.
---------------------------------------------------------------------------

    Comment: Some commenters disagreed with EPA's proposed 36-month 
timeframe for SCR retrofit. These commenters noted that, while possible 
at the unit or plant level, the collective volume of assumed SCR 
installation would not be possible given the labor constraints, supply 
constraints, and simultaneous outages necessary to complete SCR 
retrofit projects on such a schedule. They noted that many of the 
remaining coal units lacking SCR pose more site-specific installation 
challenges than those that were already retrofitted on a quicker 
timeframe.
    Response: EPA is making several changes in this final rule to 
address these concerns. First, EPA is phasing in emissions reductions 
commensurate with assumed SCR installations consistent with a 36-to-48-
month time frame in this final rule, instead of a 36-month time frame 
as proposed. EPA is implementing half of this emissions reduction 
potential in 2026 ozone-season NOX budgets for states 
containing these EGUs and the other half of this emissions reduction 
potential in 2027 ozone-season NOX budgets for those states. 
This phase-in approach to implementing SCR retrofit reduction potential 
over a three to four year period is in response to comments, including 
those from third-party full-service engineering firms. These commenters 
highlighted that while the

[[Page 36758]]

proposed 36-month time frame is viable at the plant level, it would be 
``very unlikely'' that the collective volume of SCR capacity could be 
installed in a three-year time frame based on a variety of factors. 
First, the commenters identified constraints on labor needed to 
retrofit 32 GW of capacity, highlighting that the Bureau of Labor and 
Statistics projects that there will be a decline in boilermaker 
employment over the decade and that the Associated Builders and 
Contractors (ABC) identifies the need for 650,000 additional skilled 
craft professionals on top of the normal hiring pace to meet the 
economy-wide demand created by infrastructure investment and other 
clean energy projects (e.g., carbon capture and storage). They 
highlighted the decline in companies serving this type of large-scale 
retrofit project as the lack of new coal units and the retirement of 
coal units has curtailed activity in this area over the past five 
years. They also identified supply bottlenecks for key SCR components 
that would slow the ability to implement a large volume of SCR within 3 
years, affecting electrical conduits, transformers, piping, structural 
and plate steel, and wire (with temporary price increases ranging from 
30 percent to 200 percent). Finally, commenters note that site-specific 
conditions can make retrofits for individual units a lengthier process 
than historical averages (e.g., under prior rules more accommodating 
sites retrofitted first) and that four years may be necessary for some 
projects, accordingly. EPA found the technical justification submitted 
in comment consistent with its prior assessments that a range of 39-48 
months is appropriate for SCR-retrofit timing within regional-scale 
programs.\279\ Therefore, EPA is adjusting the timeframe to still 
incentivize these reductions by the attainment date while accommodating 
the potential for some SCR retrofits to require between 36-48 months 
for installation.
---------------------------------------------------------------------------

    \279\ 86 FR 23102.
---------------------------------------------------------------------------

    Some commenters requested more than 48 months for SCR installation 
based on past projects that took five or more years. EPA disagrees with 
these commenters for two reasons. First, while EPA is identifying SCR 
retrofit potential to define significant contribution at Step 3, the 
rule only requires emissions reductions commensurate with that 
technology, implemented through a trading program, meaning that 
operators of EGUs eligible for SCR retrofit may pursue a variety of 
strategies for reducing emissions. Such compliance flexibility will 
accommodate extreme or unique circumstances in which a desired SCR 
retrofit is not achieved by the 2027 ozone season, although EPA finds 
such a circumstance exceedingly unlikely. Second, the historical 
examples that exceeded 48 months do not necessarily demonstrate that 
such projects are impossible to execute in less than 48 months, but 
rather that they can extend beyond that timeframe if no requirements or 
incentives are in place for a faster installation. As the D.C. Circuit 
has recognized, historical data on the amount of time sources have 
taken to install pollution controls do not in themselves establish the 
minimum amount of time in which those controls could be installed if 
sources are subject to a legal mandate to do so. See Wisconsin, 938 
F.3d at 330 (``[A]ll those anecdotes show is that installation can drag 
on when companies are unconstrained by the ticking clock of the 
law.'').
b. Non-EGU or Industrial Source Schedule for 2026 and Later Years
    The EPA proposed to require that all emissions reductions 
associated with the requirements for non-EGU industrial sources go into 
effect by the start of the 2026 ozone season, but also requested 
comment on its control-installation timing estimates for non-EGUs and 
requested comment on the possibility of providing for limited 
compliance extensions based on a showing of necessity. See 87 FR 20104-
05.
    Comment: The EPA received numerous comments regarding the inability 
of various non-EGU industries to install controls to comply with the 
emissions limits by 2026. Specifically, commenters raised concerns 
regarding the ability to meet these deadlines due to the ongoing 
geopolitical instability triggered by the war in Ukraine, COVID-19 
pandemic-driven disruptions, and supply chain delays and shortages. 
Commenters also claimed that the EPA's three-year installation 
timeframe for non-EGUs does not account for the time needed to obtain 
necessary permits. Commenters stated that even where controls are 
feasible for a source, some sources would need to shut down due to 
their inability to install controls by 2026 and requested that the EPA 
provide additional time for sources to come into compliance. Commenters 
from multiple non-EGU industries stated that the proposed applicability 
criteria will require controls to be installed on thousands of non-EGU 
emissions units. Because of the number of emissions units, commenters 
raised concerns with permitting delays and the unavailability of 
skilled labor and necessary components. Commenters suggested various 
timelines for control installation timing ranging from one additional 
year to seven years. Other commenters asserted that the data supported 
the conclusion that all non-EGU sources, or at least some non-EGU 
sources, could install controls by 2026 or earlier, and that EPA has a 
legal obligation to impose good neighbor requirements as expeditiously 
as practicable by such sources, including earlier than 2026 if 
possible.
    Response: After reviewing the information received during the 
public comment period and the additional information presented in the 
Non-EGU Control Installation Timing Report, the EPA has concluded that 
the majority of non-EGUs can install and operate the required controls 
by the 2026 ozone season. For the non-EGU control requirements on which 
the EPA has based its Step 3 findings as described in section V of this 
document, the emissions limits will generally go into effect starting 
with the 2026 ozone season (except where an individual source qualifies 
for a limited extension of time to comply based on a specific 
demonstration of necessity, as described in this section). The EPA 
finds that meeting the emissions limitations of this final rule through 
installation of necessary controls by an ozone season before 2026 is 
not expected to be possible for the industrial sources covered by this 
final rule.
    The EPA recognizes that labor shortages, supply shortages, or other 
circumstances beyond the control of source owner/operators may, in some 
cases, render compliance by 2026 impossible for a particular industrial 
source. Therefore, the final rule contains provisions allowing source 
owner/operators to request limited compliance extensions based on a 
case-by-case demonstration of necessity. Under these provisions, the 
owner or operator of a source may initially apply for an extension of 
up to one year to comply with the applicable emissions control 
requirements, which if approved by the EPA, would require compliance no 
later than the 2027 ozone season. The EPA may grant an additional case-
based extension of up to two additional years for full compliance, 
where specific criteria are met.
    The EPA initiated a study to examine the time necessary to install 
the potential controls identified in the final rule's cost analysis for 
all of the non-EGU industries subject to the final rule, including 
SNCR, low NOX burners, layered combustion, NSCR, SCR, fluid 
gas recirculation, and SNCR/advanced selective noncatalytic reduction

[[Page 36759]]

(ASNCR). The resulting report, which we refer to as the ``Non-EGU 
Control Installation Timing Report,'' identified a range of estimated 
installation times with minimum estimated installation times ranging 
from 6-27 months without any supply chain delays and 6-40 months with 
potential supply chain delays depending on the industry.\280\ The Non-
EGU Control Installation Timing Report also identified maximum 
estimated installation times ranging from 12-28 months without any 
supply chain delays and 12-72 months with potential supply chain delays 
depending on the industry. As indicated in the Non-EGU Control 
Installation Timing Report, the installation of layered combustion and 
NSCR control technology, in particular, could take between 9 and 72 
months depending on supply chain delays.\281\ The report also indicated 
that permitting processes may take 6 to 12 months but noted that these 
processes typically can proceed concurrent with other steps of the 
installation process.\282\
---------------------------------------------------------------------------

    \280\ See generally SC&A, NOX Emission Control Technology 
Installation Timing for Non-EGU Sources (March 14, 2023) (``Non-EGU 
Control Installation Timing Report'').
    \281\ See Non-EGU Control Installation Timing Report, Executive 
Summary (March 14, 2023).
    \282\ Id. at Section 5.6.
---------------------------------------------------------------------------

    We find that the potential time needed for permitting processes is 
generally unlikely to significantly affect installation timeframes of 
at least three years given that a source that has three or more years 
to comply is expected, in most cases, to have adequate time to apply 
for and secure the necessary permits during that time. Permitting 
processes may, however, impact shorter installation times ranging from 
12-28 months. Given the 12-28 month estimate for minimum and maximum 
installation times without supply chain delays and permitting 
timeframes typically ranging from 6-12 months, the EPA finds that the 
controls for non-EGU sources needed to comply with this final rule are 
generally not expected to be installed significantly before the 2026 
ozone season.
    Generally, the Non-EGU Control Installation Timing Report indicated 
that all non-EGU unit types subject to the final rule could install 
controls within 28 months if there are no supply chain delays. Thus, 
the Non-EGU Control Installation Timing Report confirms that for any 
individual facility, meeting the emissions limitations of this final 
rule through installation of controls can be completed by the start of 
the 2026 ozone season. It is only when the number of units in the U.S. 
potentially affected by the rule is taken into account, coupled with 
broader considerations of economic capacity including current 
information on supply-chain delays, that the potential need for 
additional time beyond 2026 becomes a possibility. Under ideal economic 
conditions (i.e., no supply-chain delays or other constraints), 
affected units are estimated to be capable to install both combustion 
and post-combustion controls before the 2026 ozone season. Many 
commenters, however, provided information on installation timing 
estimates based on current supply chain delays and labor constraints. 
These commenters generally stated that installation of the necessary 
controls for some units would take longer than three years if supply 
chain delays similar to those that have occurred over the past few 
years continue. The Non-EGU Control Installation Timing Report 
reflected this information, together with additional information 
gathered from pollution control vendors, to develop ranges of estimates 
of possible installation times given current (i.e., 2022) labor market 
conditions and material supplies. The Non-EGU Control Installation 
Timing Report also discussed how the installation and optimization of 
post-combustion controls over a similar timeframe at both EGUs and non-
EGUs subject to this final rule would, considered cumulatively, 
potentially affect the installation timing needs of the covered non-EGU 
sources.
    Based on information provided by commenters and vendors, the Non-
EGU Control Installation Timing Report indicated that if current supply 
chain delays continue, control installations could take as long as 61 
months for most non-EGU industries and possibly as long as 64-112 
months in difficult cases. Notably, however, the conclusions in the 
Non-EGU Control Installation Timing Report reflect three key 
assumptions that could result in the relatively lengthy timing 
estimates at the outer end of this range: (1) the current state of 
supply chain delays and disruptions would continue without any increase 
in labor supply, materials, or reduction in fabrication timing; (2) the 
labor and materials markets would not adjust in response to this rule 
in the timeframe needed to meet the increased demand for control 
installations; and (3) the Report was unable to account for some of the 
flexibilities built into the final rule that will allow owners and 
operators to install controls on the most cost-effective units with 
shorter installation times.
    As presented in the Non-EGU Control Installation Timing Report, 
supply chain delays and disruptions have generally been lessening since 
they peaked in 2020 during the COVID-19 pandemic, and many economic 
indicators have showed some improvement towards pre-pandemic levels, 
including freight transportation, inventory to sales ratios, interstate 
miles traveled, U.S. goods imports, and supply chain indices.\283\ If 
these economic indicators continue to improve and the availability of 
fabricators and materials continues to trend upward, the control timing 
estimates identified in the Non-EGU Control Installation Timing Report 
could prove to be overstated for some industries and control 
technologies. In addition, the Non-EGU Control Installation Timing 
Report did not account for the labor and supply market adjustments that 
would be anticipated to occur to meet increased demand for control 
technologies and related materials and labor over the next several 
years in response to the rule. Cf. Wisconsin, 938 F.3d at 330 (``[A]ll 
those anecdotes [of elongated control installation times] show is that 
installation can drag on when companies are unconstrained by the 
ticking clock of the law.''). For example, some of the longer 
installation timeframes identified in the Non-EGU Control Installation 
Timing Report are based on assumed limits on the current availability 
of skilled labor needed to install combustion controls and post 
combustion controls. If the market adjusts in response to increasing 
demand for this type of skilled labor in the timeframe needed for 
compliance (e.g., there is an increase in boilermaker and engine 
controls labor), the installation timing estimates in the Non-EGU 
Control Installation Timing Report again could be overstated.
---------------------------------------------------------------------------

    \283\ Id. at Section 6.1.
---------------------------------------------------------------------------

    The Non-EGU Control Installation Timing Report also did not account 
for flexibilities provided in this final rule that will enable owners 
and operators of certain affected units to identify the most cost-
effective and efficient means for installing any necessary controls. 
For example, one concern highlighted by commenters was the amount of 
time necessary to install controls on engines that have been in 
operation for 50 or more years. The requirements that we are finalizing 
for engines in the Pipeline Transportation of Natural Gas industry 
include an exemption for emergency engines and provisions allowing 
source owner/operators to request the EPA approval of facility-wide 
emissions averaging plans, both of which enable owners and operators of 
affected units to take costs, installation timing needs,

[[Page 36760]]

and other considerations into account in deciding which engines to 
control.
    In response to industry concern about the number and size of units 
captured by the proposed applicability criteria, the EPA has made 
several changes to the applicability criteria in the final rule to 
focus the control requirements on impactful non-EGU units. As explained 
further in section VI.C of this document, the EPA is establishing 
exemptions for low-use boilers and engines where it would not be cost-
effective to require controls at this time. Finally, as discussed in 
section VI.C.3 of this document, the EPA is not finalizing the proposed 
requirements for most emissions unit types in the Iron and Steel Mills 
and Ferroalloy Manufacturing industry given the EPA does not currently 
have a sufficient technical basis for finalizing those proposed 
requirements. These changes reduce the number of non-EGU units that 
will actually need to install controls and should reduce the strain on 
the labor and supply chain and permitting processes. For example, for 
engines, the EPA estimates that the facility-wide emissions averaging 
provision would, in many cases, allow facilities to install controls on 
only one-third of their engines, on average (see section VI.C.1 of this 
document for further discussion).
    Taking all of these considerations into account, the EPA finds that 
the outer range of timing estimates presented in the Non-EGU Control 
Installation Timing Report generally reflects a conservative set of 
installation timing estimates and that the factors described previously 
could result in installation timeframes that fall toward the shorter 
end of the ranges of time that factor in supply-chain delays or could 
obviate those supply-chain delay issues entirely.
    Based on all of these considerations, the EPA has concluded that 
three years is generally an adequate amount of time for the non-EGU 
sources covered by this final rule to install the controls in the 20 
states that remain linked in 2026. The EPA also recognizes, however, 
that some sources may not be able to install controls by the 2026 ozone 
season despite making good faith efforts to do so, due to the 
aforementioned supply chain delays or other circumstances entirely 
beyond the owner or operator's control. Therefore, the final FIPs 
require compliance with the emissions control requirements for non-EGUs 
by the beginning of the 2026 ozone season, with limited exceptions 
based on a showing of necessity for individual sources that meet 
specific criteria. Where an individual owner or operator submits a 
satisfactory demonstration that an extension of time to comply is 
necessary, due to circumstances entirely beyond the owner or operator's 
control and despite all good faith efforts to install the necessary 
controls by May 1, 2026, the EPA may determine that installation by 
2026 is not possible and thereby grant an extension of up to one year 
for that source to fully implement the required controls. If, after the 
EPA has granted a request for an initial compliance extension, the 
source remains unable to comply by the extended compliance date due to 
circumstances entirely beyond the owner or operator's control and 
despite all good faith efforts to install the necessary controls by the 
extended compliance date, the owner or operator may request and the EPA 
may grant a second extension of up to two additional years for full 
compliance, where specific criteria are met. This application process 
is generally in accordance with the concept on which the Agency 
requested comment in the proposal, see 87 FR 20104-05, and is modeled 
on a similar process provided for industrial sources subject to CAA 
section 112 NESHAPs, found at 40 CFR 63.6(i)(3).
    The EPA intends to grant a request for an initial compliance 
extension only where a source demonstrates that it has taken all steps 
possible to install the necessary controls by the applicable compliance 
date and still cannot comply by the 2026 ozone season, due to 
circumstances entirely beyond its control. Any request for a compliance 
extension must be received by the EPA at least 180 days before the May 
1, 2026, compliance date. The request must include all information 
obtained from control technology vendors demonstrating that the 
necessary controls cannot be installed by the applicable compliance 
date, any permit(s) secured for the installation of controls or 
information from the permitting authority on the timeline for issuance 
of such permit(s) if the source has not yet obtained the required 
permit(s); and any contracts entered into by the source for the 
installation of the control technology or an explanation as to why no 
contract is necessary. The EPA may also consider documentation of a 
source owner's/operator's plans to shut down a source by the 2027 ozone 
season in determining whether a source is eligible for a compliance 
extension. The owner or operator of an affected unit remains subject to 
the May 1, 2026 compliance date unless and until the Administrator 
grants a compliance extension.
    The EPA intends to grant a request for a second compliance 
extension beyond 2027 only where a source owner/operator submits 
updated documentation showing that it is not possible to install and 
operate controls by the 2027 ozone season, despite all good faith 
efforts to comply and due to circumstances entirely beyond its control. 
The request must be received by the EPA at least 180 days before the 
extended compliance date and must include, at minimum, the same types 
of information as that required for the initial extension request. The 
owner or operator of an affected unit remains subject to the initial 
extended compliance date unless and until the Administrator grants a 
second compliance extension. A denial will be effective on the date of 
denial.
    As discussed earlier in section VI.A, in Wisconsin the court held 
that some deviation from the CAA's mandate to eliminate prohibited 
transport by downwind attainment deadlines may be allowed only ``under 
particular circumstances and upon a sufficient showing of necessity.'' 
\284\ This standard is met when, in the EPA's judgment, compliance by 
the attainment date amounts to an impossibility. The EPA cannot allow a 
covered industrial source to avoid timely compliance with the emissions 
control requirements established in this final rule unless the source 
owner/operator can demonstrate that compliance by the 2026 ozone season 
is not possible due to circumstances entirely beyond their control. The 
criteria that must be met to qualify for limited extensions of time to 
comply are designed to meet this statutory mandate. The EPA anticipates 
that the majority of the industrial sources covered by this final rule 
will not qualify for a compliance extension.
---------------------------------------------------------------------------

    \284\ Wisconsin, 938 F.3d 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'').
---------------------------------------------------------------------------

B. Regulatory Requirements for EGUs

    To implement the required emissions reductions from EGUs, the EPA 
is revising 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. The EPA is using 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

[[Page 36761]]

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. Thus, while the 
Step 3 control-stringency determination for EGUs to eliminate 
significant contribution is based on strategies that do not require 
generation shifting or reduced utilization of EGUs, 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.
    To ensure emissions reductions necessary to eliminate significant 
contribution are maintained, in this rulemaking, the EPA is making 
certain enhancements to the current provisions of the Group 3 trading 
program addressing emissions-control performance by some kinds of 
individual units that will necessarily reduce the flexibility of the 
program to some extent for those units. In analyzing significant 
contribution at Step 3, once a linkage has been established between an 
upwind state and a downwind receptor, we identify an appropriate set of 
emissions control strategies, considering cost and other factors, that 
would eliminate significant contribution from the upwind state without 
leading to undercontrol or overcontrol at the downwind linked 
receptors. At Step 4, for EGUs, we develop emissions budgets based on 
consistent application of the identified strategies to the sources. 
This level of emission control at each source identified in Step 3 is 
what the EPA deems to eliminate significant contribution, while the 
design of emission budgets that successfully implement that level of 
emission control is determined at Step 4. See section III.B and V.
    The trading program enhancements discussed in this section are 
designed to ensure that sources actually achieve that level of emission 
control and thereby eliminate significant contribution on a permanent 
basis at Step 4. The enhancements ensure that the emissions budgets for 
EGUs continue to secure the level of emission control identified at 
Step 3 at the sources active in the trading program on a more 
consistent basis throughout each ozone season than prior transport 
trading programs (including those that did not provide complete 
remedies for interstate pollution transport) have required. An 
alternative form of implementation at Step 4 would be to implement 
source-specific emissions limitations (e.g., rate-based standards 
expressed as mass per unit of heat input) reflecting the control 
strategies identified at Step 3. This is a very common form of 
implementation for many other CAA requirements and is indeed the manner 
of implementation selected in this very rulemaking for other affected 
industrial sources. See sections III.B, V.D.4, and VI.C. But doing so 
would require loss of the flexibilities inherent in a trading program, 
inclusive of these enhancements, that facilitate orderly and timely 
achievement of the required emission reductions in the power sector.
    Prior to this rule, the Group 3 trading program has applied 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 will 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 is expanding 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 
seven states currently covered by the CSAPR NOX Ozone Season 
Group 2 Trading Program (the ``Group 2 trading program'')--Alabama, 
Arkansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin--will 
transition from the Group 2 trading program to the revised Group 3 
trading program at the beginning of the 2023 control period,\285\ and 
affected EGUs within the borders of the three states not currently 
covered by any CSAPR trading program for seasonal NOX 
emissions--Minnesota, Nevada, and Utah--will enter the Group 3 trading 
program in the 2023 control period on the effective date of this rule. 
As discussed in section VI.B.12.a of this document, because the 
effective date of the rule will likely be sometime during the 2023 
ozone season, special transitional provisions have been developed to 
allow for efficient administration of the rule's EGU requirements 
through the Group 3 trading program while not imposing any new 
substantive obligations on parties prior to the rule's effective date, 
similar to the transitional provisions implemented under the Revised 
CSAPR Update.
---------------------------------------------------------------------------

    \285\ Affected EGUs in the three other states currently covered 
by the Group 2 trading program--Iowa, Kansas, and Tennessee--will 
continue to participate in that program.
---------------------------------------------------------------------------

    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 
will include new units as well as existing units and will also include 
units located in Indian country within the state's borders. Sections 
VI.B.2 and VI.B.3 of this rule provide additional discussion of the 
geographic expansion of the Group 3 trading program and the units in 
the expanded geography that will become subject to the program under 
the program's existing applicability provisions.
    In addition to expanding the Group 3 trading program's geographic 
scope, the EPA is modifying the program's regulations prospectively to 
include certain enhancements to improve environmental outcomes. Two of 
the proposed enhancements will 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 is revising the trading program regulations to 
include a dynamic budgeting procedure. Under this procedure, the EPA 
will calculate emissions budgets for control periods in 2026 and later 
years based on more current information about the composition and 
utilization of the EGU fleet, specifically data available from the 2024 
ozone season and following (e.g., for 2026, data from periods through 
2024; for 2027, data from periods through 2025; etc.). Through the 2029 
control period, the dynamically determined budgets will apply only if 
they are higher than preset budgets established in the rule. 
(Associated revisions to the program's variability limits and unit-
level allowance allocation procedures will coordinate these provisions 
with the revised budget-setting procedures.) Second,

[[Page 36762]]

starting with the 2024 control period, the EPA will 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 a preset percentage of the sum of the 
state emissions budgets for each control period. The preset percentage 
will be 21 percent for control periods through 2029 and 10.5 percent 
for control periods in 2030 and later years. Together, these 
enhancements will protect the intended stringency of the trading 
program against potential erosion caused by EGU fleet turnover and will 
better sustain over time the incentives created by the trading program 
to achieve the degree of emissions control for EGUs that the EPA has 
determined is necessary to address states' good neighbor obligations.
    Two further enhancements to the Group 3 trading program 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 coal-fired EGUs with existing 
SCR controls and the earlier of the 2030 control period or the control 
period after which an SCR is installed for other large coal-fired EGUs, 
a daily NOX emissions rate of 0.14 lb/mmBtu will apply as a 
backstop to the seasonal emissions budgets (which are based on an 
assumed seasonal average emissions rate of 0.08 lb/mmBtu for EGUs with 
existing SCR controls). Each ton of emissions exceeding a unit's 
backstop daily emissions rate, after the first 50 such tons, in a given 
control period will 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., typically 121 percent of the state's 
emissions budget), will be strengthened by the addition of another 
backstop requirement. Specifically, for any unit equipped with post-
combustion controls that is found responsible for contributing to an 
exceedance of the state's assurance level, the revised regulations will 
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.\286\
---------------------------------------------------------------------------

    \286\ 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 all units with 
post-combustion 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 the 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 V of this document. 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 better ensure that each state's significant 
contribution is fully eliminated by this action, see North Carolina, 
531 F.3d at 919-21. In addition to addressing the statutory 
requirements of eliminating significant contribution, the EPA 
anticipates that these enhancements will also deliver public health and 
environmental benefits to underserved and overburdened communities.
    The revisions to the Group 3 trading program being finalized in 
this rule are very similar to the proposed revisions. The changes from 
proposal to the set of states covered are driven largely by updates to 
the air quality modeling performed for the final rule, as described in 
section IV of this document. The changes from proposal to the trading 
program enhancements are generally being made in response to comments 
on the proposal, as discussed in more detail in the remainder of 
section VI.B of this document.
1. Trading Program Background and Overview of 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 protective 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 have been 
nearly identical in their core design elements and their regulatory 
text.\287\ The principal common design elements currently reflected in 
all of the programs are as follows:
---------------------------------------------------------------------------

    \287\ 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 the 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 the 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

[[Page 36763]]

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 CSAPR 
programs do not limit trading of allowances, and prior to this rule 
have not limited banking of allowances within a given trading program, 
the 3-for-1 surrender ratio imposed by the 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.\288\
---------------------------------------------------------------------------

    \288\ As discussed in section VI.B.6 of this document, while 
allowance banking has not previously been limited under any of the 
CSAPR trading programs, limits on the use of banked allowances were 
included in the earlier NOX Budget Trading Program in the 
form of ``flow control'' provisions.
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     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 the 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 historical CSAPR trading 
program structure established by the common design elements just 
described 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 many 
stakeholders' concerns about whether the historical 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 protectiveness and short-term form 
of the ozone standard. One set of concerns relates to the historically 
observed tendency under the 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 or run less optimally existing emissions controls even 
when a linkage between the sources' state and a receptor persists. For 
example, certain units in Ohio and Pennsylvania have been found to have 
operated their controls below target emissions performance levels used 
for budget setting under the CSAPR Update in the 2019-2021 period, even 
though the Revised CSAPR Update found that these states remained linked 
through at least 2021 to receptors for the 2008 ozone NAAQS, and the 
CSAPR Update itself was only a partial remedy. See 86 FR 23071, 23083. 
While this unit-level behavior may have been permissible under the 
prior program, 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. This indicates that the prior program design was not 
effectively ensuring the elimination of significant contribution.\289\
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    \289\ We also observe that these sources' emissions have the 
potential to impact downwind overburdened communities. See Ozone 
Transport Policy Analysis Final Rule TSD, Section E. The EPA 
conducted a screening-level analysis to determine whether there may 
be impacts on overburdened communities resulting from those EGUs 
receiving backstop emissions rates under this rule. This analysis 
identified a greater potential for these sources to affect areas of 
potential concern than the national coal-fired EGU fleet on average. 
However, this analysis is distinct from the more comprehensive 
exposure analysis conducted as discussed in section VII of this 
document and the RIA. In addition, we note that our conclusions 
regarding the EGU trading program enhancements in this final rule 
are wholly supportable and justified under the good neighbor 
provision, even in the absence of any potential benefits to 
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 ensure emissions control on critically important 
highest ozone days, guard against non-operation of emissions controls 
under a more protective NAAQS, and provide assurance of elimination of 
significant contribution to downwind areas, while also maintaining 
appropriate compliance and operational flexibility for EGUs, the EPA in 
this rule is implementing a suite of enhancements to the trading 
program. These will help to ensure reductions occur on the highest 
ozone days commensurate with our Step 3 determinations, in addition to 
maintaining a mass-based seasonal requirement. To meet the statutory 
mandate to eliminate significant contribution and interference with

[[Page 36764]]

maintenance on the critically important days, this combination of 
provisions will strongly incentivize sources to plan to run controls 
all season, including on the highest ozone days, while giving 
reasonable flexibility for occasional operational needs.\290\
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    \290\ Deferral of the backstop daily emissions rate for certain 
EGUs, for reasons discussed in section VI.B.7 of this document, does 
not alter this finding that this trading program enhancement is an 
important part of the solution to eliminating significant 
contribution from EGUs under CAA section 110(a)(2)(D)(i)(I).
---------------------------------------------------------------------------

    In this rulemaking, the EPA is revising the Group 3 trading program 
to include enhancements designed to address both sets of concerns 
described previously. The principles guiding the various revisions and 
the relationships of the revisions to one another are discussed in 
sections VI.B.1.b and VI.B.1.c of this document. The individual 
revisions are discussed in more detail in sections VI.B.4 through 
VI.B.9 of this document.
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 
performance level as the EGU fleet evolves over time. Under the 
historical structure of the 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 historical 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 
at Step 3, the EPA has then for purposes of Step 4 implementation 
program design 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 conditions unfold in practice 
that differ from the projections made at the time of a rulemaking for 
these other factors, 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 
beyond the relatively near-term analytic years of 2023 and 2026 given 
particular attention in this rulemaking has become increasingly 
challenging in light of the anticipated continued evolution of the 
electric power sector toward more efficient and cleaner sources of 
generation, including as driven by incentives provided by the 
Infrastructure Investment and Jobs Act as well as the Inflation 
Reduction Act.
    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 four 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).\291\ 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.\292\ \293\ While the EPA had previously provided analysis 
focusing on the year of initial program implementation, when allowance 
prices were high (i.e., 2017 for the CSAPR Update), to demonstrate that 
on average, sources operate their controls more effectively on high 
electric demand days, even in that case it had identified situations 
where particular units failed to optimize their controls on these days. 
In later years, when allowance prices had fallen, more sources, 
including some identified by commenters, had idled or reduced the 
effectiveness of their controls. Such an outcome undermined the ongoing 
achievement of emissions rate performance consistent with the control 
strategies identified in the CSAPR Update to eliminate significant 
contribution to nonattainment and interference with maintenance, 
despite the fact that the mass-based budgets were being met.
---------------------------------------------------------------------------

    \291\ The price of allowances in CSAPR Update states started 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).
    \292\ 86 FR 23117.
    \293\ See EPA-HQ-OAR-2020-0272-0094 (``[This] 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

[[Page 36765]]

years though 2024 that reflect future EGU fleet changes known with 
reasonable certainty at the time of the rulemaking. Some commenters in 
that rulemaking 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 2022, it appears that 
the emissions budgets set for the first two control periods covered by 
the Revised CSAPR Update generally succeeded at creating incentives to 
operate emissions controls under the Group 3 trading program for those 
control periods. However, the EPA recognizes that the lack of emissions 
budget adjustments after 2024 in conjunction with industry trends 
toward more efficient and cleaner resources will likely lead to a 
surplus of allowances after the adjustments end. This prospect for the 
existing Group 3 trading program should be avoided by the changes being 
made in this rulemaking. In this rulemaking, besides establishing new 
preset emissions budgets for the 2023 through 2029 control periods, the 
EPA is also extending the Group 3 trading program budget-setting 
methodology used in the Revised CSAPR Update to routinely calculate 
dynamic emissions budgets for each future control period from 2026 on, 
to be published in the year before that control period, with each 
dynamic emissions budget generally reflecting the latest available 
information on the composition and utilization of the EGU fleet at the 
time that dynamic emissions budget is determined. For the control 
periods in 2026 through 2029, each state's final emissions budget will 
be the preset budget determined for the state in this rulemaking except 
in instances when the dynamic budget determined for the state (and 
published approximately one year before the control period using the 
dynamic budget-setting methodology) is higher. For control periods in 
2030 and thereafter, the emissions budgets will be the amounts 
determined for each state in the year before the control period using 
the dynamic budget-setting methodology.
    The current budget-setting methodology established in the Revised 
CSAPR Update and the revisions being made to that methodology are 
discussed in detail in section VI.B.4 of this document and the Ozone 
Transport Policy Analysis Final Rule TSD. To summarize here, the 
methodology used to determine the preset budgets largely follows the 
Revised CSAPR Update's emissions budget-setting methodology, which 
included 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 has determined the 
preset state emissions budgets for the control periods from 2023 
through 2029 by using the Revised CSAPR Update's budget-setting 
methodology, except that the step of that methodology intended to 
reflect the effects of generation shifting has been eliminated.
    The dynamic budget-setting methodology used to determine dynamic 
state emissions budgets in the year before each control period starting 
with the 2026 control period is set forth in the revised Group 3 
trading program regulations at 40 CFR 97.1010(a). This methodology 
modifies the Revised CSAPR Update's budget-setting methodology in two 
ways. First, the baseline EGU inventory and heat input data, but not 
the emissions rate data, will be updated for each control period using 
the most recent available reported data in combination with reported 
data from the four immediately preceding years. For example, in early 
2025, using the final data reported for 2020 through 2024, the EPA will 
update the baseline inventory and heat input data used to determine 
dynamic state emissions budgets for the 2026 control period.\294\ 
Second, the EPA will 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 reported heat input data 
used to update the baseline.
---------------------------------------------------------------------------

    \294\ As discussed in section VI.B.4 of this document, the 
state-level data used to determine the overall state-level heat 
input for computing a state's dynamic budget will be a three-year 
average (e.g., 2022-2024 state-level data will be used in 2025 to 
set the 2026 dynamic budgets). The unit-level data used to determine 
individual units' shares of the state-level heat input in the 
computations will be the average of the three highest non-zero heat 
input amounts for the respective units over the most recent five 
years (e.g., 2020-2024 unit-level data will be used in 2025 to set 
the 2026 dynamic budgets).
---------------------------------------------------------------------------

    The EPA believes that the revisions to the emissions budget-setting 
process will substantially improve the ability of the emissions budgets 
to keep pace with changes in the composition and utilization of the EGU 
fleet. The dynamic budget-setting methodology will 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, and through 2029 the preset budgets established in the 
rule will also account for these factors to the extent known. The 
dynamic budget-setting methodology will 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 dynamic budget-setting 
procedure is specified in this final rule's trading program regulations 
and the computations, which are straightforward, can be performed in a 
spreadsheet to deliver reliable results. The EPA will provide public 
notice of the preliminary calculations and the data used by March 1 of 
the year preceding the control period and will provide an opportunity 
for submission of any objections to the data and preliminary 
calculations before finalizing the dynamic budgets for each control 
period by May 1 of the year before the control period to which those 
dynamic budgets apply. Thus, for example, sources and other 
stakeholders will have certainty by May 1, 2025, of the dynamic 
emissions budgets that will be calculated for the 2026 control period 
that starts May 1, 2026. Moreover, as of the issuance of this final 
rule, stakeholders will know the state-level preset emissions budgets 
for the 2026-2029 control periods, which serve as floors that will only 
be supplanted by dynamic budgets calculated for those control periods 
if such a dynamic budget yields a higher amount of tons than the 
corresponding preset budget established in this action.
    It bears emphasis that the annually updated information used in the 
dynamic budget-setting computations will concern only the composition 
and utilization of the EGU fleet and not the emissions rate data also 
used in those computations. The dynamically determined emissions budget 
computations for all years will reflect only the specific emissions 
control

[[Page 36766]]

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 will eliminate 
emissions as determined to be required under the good neighbor 
provision. The stringency of the emissions budgets will simply reflect 
the stringency of the emissions control strategies determined in the 
Step 3 multifactor analysis and will do so more consistently over time 
than the EPA's previous approach of computing emissions budgets for all 
future control periods at the time of the rulemaking.
    The rule's revisions relating to state emissions budgets and the 
budget-setting process generally follow the proposal except for two 
changes we are making in response to comments, specifically: we will 
use historical data from multiple years rather than a single year in 
the dynamic budget-setting process, and we are establishing preset 
emissions budgets for the 2026-2029 control periods such that the 
dynamic budgets for those control periods will only be imposed where 
they exceed the corresponding preset budgets finalized in this rule. 
The rationale for these changes is discussed later in this section as 
part of the responses to the relevant comments. Details of the final 
budget-setting methodology and responses to additional comments are 
discussed further in section VI.B.4 of this document.
    The final rule's provisions relating to the determination of state-
level variability limits and assurance levels and unit-level allowance 
allocations are coordinated with the budget-setting methodology. These 
provisions generally follow the proposal except that the change to the 
methodology for determining variability limits is implemented starting 
with the 2023 control period instead of the 2025 control period and the 
final methodology for determining unit-level allocations of allowances 
to coal-fired units considers the controlled emissions rate assumptions 
applicable to the same units in the budget-setting process. Details of 
these provisions, including the rationales for the changes from 
proposal, are discussed in sections VI.B.5 and VI.B.9, 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 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,\295\ 
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 allowance 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.
---------------------------------------------------------------------------

    \295\ 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. 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. Therefore, section 
VI.B.1.c of this document discusses the enhancements to the Group 3 
trading program that the EPA is making 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.
---------------------------------------------------------------------------

    As discussed in detail in section VI.B.6 of this rule, the EPA is 
revising the Group 3 trading program by adding provisions that 
establish a routine recalibration process for banked allowances that 
will 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 will 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 level computed as 
a target percentage of the sum of the state emissions budgets for the 
current control period. The target percentage will be 21 percent for 
the 2024-2029 control periods and 10.5 percent for control periods in 
2030 and later years. The recalibration procedure entails identifying 
the ratio of the target bank amount to the total quantity of banked 
allowances held in all accounts before the recalibration and then, if 
the ratio is 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.
    As noted previously, recalibration of the bank for each control 
period will be carried out in August of that control period. This 
timing will accommodate the process of deducting allowances for 
compliance for the previous control period, which cannot be completed 
before sources' June 1 compliance deadline for the previous control 
period, and will then provide approximately two additional months for 
sources to engage in any desired allowance transactions before 
recalibration occurs. However, data that can be used to estimate the 
bank recalibration ratio for each control period will be available 
shortly after the end of the previous control period, and the EPA will 
use these data to make information on the estimated bank recalibration 
ratio for each control period publicly available no later than March 1 
of the year of that control period, thereby facilitating the ability of 
affected EGUs to anticipate their ultimate holdings of recalibrated 
banked allowances to inform their compliance planning for that control 
season. Affected EGUs will also have several months following the 
completed bank recalibration in August to transact allowances with 
other parties as needed

[[Page 36767]]

before the allowance transfer deadline of June 1 of the following year.
    The EPA believes this revision to the Group 3 trading program's 
banking provisions establishing an annual bank recalibration process 
will complement the revisions to the budget-setting process by 
preventing 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.
    The calibration procedure will 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 will be left in the 
account after the recalibration for possible sale or use in meeting 
future compliance requirements. Because the banked allowances will 
always have value, the opportunity to bank allowances will continue to 
advance the purposes served by otherwise unrestricted banking as 
described previously. 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 final rule's provisions relating to bank recalibration 
generally follow the proposal except that, in response to comments, the 
target percentage used to determine the recalibrated bank levels for 
the 2024-2029 control periods is being set at 21 percent instead of 
10.5 percent. The rationale for this change is discussed later in this 
section as part of the responses to the relevant comments. Details of 
the bank recalibration provisions are discussed further in section 
VI.B.6 of this rule.
c. 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 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.
    This EPA intends that the trading program enhancements described in 
section VI.B.1.b of this rule will improve the Group 3 trading 
program's ability to sustain emissions control incentives over time 
such that needed emissions performance will 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 to 
the elimination of significant contribution in keeping with the EPA's 
Step 3 determinations, the EPA is supplementing the previously 
discussed enhancements with two other new sets of provisions that will 
apply to certain individual units within the larger context of the 
Group 3 trading program. The allowance price will continue to be the 
most important driver of good environmental performance for most units, 
but the proposed unit-level requirements will be important supplemental 
drivers of performance and will offer additional assurance that 
significant contribution is eliminated on a daily basis during the 
ozone season by more continuous operation of existing pollution 
controls.
i. Unit-Specific Backstop Daily Emissions Rates
    The first of the 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 will 
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) will 
apply to emissions during the ozone season from any large coal-fired 
EGU with existing SCR controls exceeding by more than 50 tons a daily 
average NOX emissions rate of 0.14 lb/mmBtu. The additional 
allowance surrender requirement will 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 will have to 
be surrendered by the same compliance deadline of June 1 after each 
control period. The amount of additional allowances to be surrendered 
will 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, computing the amount 
of any excess over 50 tons, and multiplying by two. Starting with the 
second control period in which newly installed SCR controls are 
operational, but not later than the 2030 control period, the 3-for-1 
surrender ratio will apply in the same way to all large coal-fired EGUs 
except circulating fluidized bed units, consistent with EPA's 
determination that a control stringency reflecting installation and 
operation of SCR controls on all such large coal-fired EGUs is 
appropriate to address states' good neighbor obligations with respect 
to the 2015 ozone NAAQS.
    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.\296\ 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 in section V.B.1.a of this document and in the EGU 
NOX Mitigation Strategies Final Rule TSD in the docket. 
While the EPA has in prior ozone transport actions not found sufficient 
evidence of emissions control idling or non-optimization to take the 
step of building in enhancements to the trading program to ensure unit-
level control operation, our review of subsequent-year data for prior 
programs suggests that the non-optimization

[[Page 36768]]

behavior increases in the latter years of a program. Applied to this 
context (e.g., a rule providing a full remedy to interstate transport 
for the more protective 2015 ozone NAAQS and an extended period of 
expected persistence of receptors), this data suggests this 
deterioration in performance could become prevalent and problematic in 
future years if not addressed. 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 rule to ensure the emissions control strategy selected 
at Step 3 is indeed implemented at Step 4. Thus, particularly in the 
context of the more protective 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 emissions 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. 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 
Policy Analysis Final Rule 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. Thus, the EPA is adopting backstop daily rate limits at the 
individual unit level because it is appropriate and justified in the 
context of eliminating significant contribution under CAA section 
110(a)(2)(D)(i)(I). While the former justification is sufficient to 
finalize this enhancement to the trading program, we also anticipate 
that this measure will deliver public health and environmental benefits 
to overburdened communities (as well as the rest of the 
population).\297\
---------------------------------------------------------------------------

    \296\ E.g., comments of Maryland Department of the Environment 
on the proposed Revised CSAPR Update at 3, EPA-HQ-OAR-2020-0272-
0094.
    \297\ Nonetheless, the environmental justice exposure analysis 
indicates that preexisting disparities among demographic groups are 
likely to persist even under this final rule. See section VII of 
this document.
---------------------------------------------------------------------------

    We considered whether, as some commenters suggested, it would be 
appropriate to simply implement unit-specific daily emissions 
limitation at all of the large, coal-fired EGUs, and forego an 
emissions trading approach altogether. While this is within the EPA's 
statutory authority, see CAA section 110(a)(2)(A) and 302(y), and 
merits careful consideration, we are declining to do so in this action 
but intend to closely monitor EGU emissions performance in response to 
the trading program finalized here. The purpose of establishing a 
backstop daily NOX emissions rate and implementing it 
through additional allowance surrender requirements instead of as an 
enforceable emissions limitation 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 VI.B.7 of this document, under the EPA's historical trading 
programs without the enhancements made 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. Collectively, this non-optimization of 
existing controls has a detrimental impact on problematic receptors. 
Table V.D.1-1 shows the expected air quality benefit from control 
optimization (totaling nearly 1.6 ppb change across all 
receptors).\298\
---------------------------------------------------------------------------

    \298\ As illustrated in the table and underlying data, a small 
portion of this ppb impact is attributable to combustion control 
upgrade potential.
---------------------------------------------------------------------------

    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 included in Appendix G of 
the Ozone Transport Policy Analysis Final 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 emissions 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.\299\
---------------------------------------------------------------------------

    \299\ EPA-HQ-OAR-2020-0272-0094.
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    The EPA believes that the design of the daily emissions rate 
provisions will 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 will 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. 
Moreover, the EPA believes that the inclusion of a 50-ton threshold 
before the increased surrender requirements would apply is sufficient 
to address virtually all instances where a unit's emissions would 
exceed the 0.14 lb/mmBtu daily rate because of unavoidable startup or 
shutdown conditions during which SCR equipment cannot be operated, 
thereby ensuring that the provision will not penalize units for 
emissions that are beyond their reasonable control.
    The EPA is applying 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 a common practice for the best 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 and installed on nearly 100 
percent of the coal fired boilers in the top quartile of emissions rate 
performance. In the context of addressing good neighbor obligations 
with respect to the 2015 ozone NAAQS, the EPA is determining that a 
control stringency reflecting universal installation and operation of 
SCR technology at large coal-fired EGUs (other than circulating 
fluidized bed units) is appropriate at Step 3. Finally, where SCR 
controls are installed on such units, optimized operation of those 
controls is an extremely cost-effective method of achieving 
NOX emissions

[[Page 36769]]

reductions. The EPA believes these considerations support establishment 
of the 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 including some SCR controls at gas-
fired steam units in the selected control stringency at Step 3, the EPA 
is not including universal SCR controls at gas-fired steam units. 
Because the EPA is not determining 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 applying 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 level of the daily average NOX 
emissions rate--0.14 lb/mmBtu--through analysis of historical data, as 
described in section VI.B.7 of this document. 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 
will 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 will be reflected in the state emissions 
budgets under this rule. For these units, not applying the daily 
average rate provisions until 2024 serves three purposes. First, it 
provides 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 will be held 
to increased allowance-surrender consequences for exceeding the daily 
rate. Second, it provides 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 will apply to the SCR-equipped units based on the combined 
NOX emissions rates measured in the common stacks. Third, it 
provides all units sufficient time to update the data handling software 
in their existing monitoring systems as needed to compute and report 
the additional hourly and daily data values needed for implementation 
of the provisions.\300\
---------------------------------------------------------------------------

    \300\ For further discussion of emissions monitoring and 
reporting requirements under the rule, including the options 
available to plants where SCR-equipped and non-SCR-equipped coal-
fired units exhaust to common stacks, see section VI.B.10 of this 
document.
---------------------------------------------------------------------------

    With respect to the units without existing SCR controls, the daily 
average emissions rate provisions will apply starting with the second 
control period in which newly installed SCR controls are operational at 
the unit, but not later than the 2030 control period. This 
implementation timing represents a change from the proposal, under 
which the daily average emissions rate provisions would have applied to 
units without existing SCR starting in the 2027 control period. 
Commenters noted that for many units without SCR, replacement of the 
unit within a few years, and shifting of some generation to cleaner 
units in the interim, would be a more economic compliance strategy than 
installation of new SCR controls. The commenters further noted that 
implementation of the daily average emissions rate for these units 
starting in 2027 would strongly disadvantage such an alternative 
strategy if the capacity replacement and any associated transmission 
improvements could not be implemented by 2027. In light of these 
comments, the EPA has determined that as long as the emissions budgets 
determined in this rule to eliminate significant contribution are still 
being implemented as expeditiously as practicable--which in this 
instance the EPA has determined requires phasing in the required 
emissions reductions by 2027--it is reasonable to defer implementation 
of the daily average emissions rate provisions to 2030 for units 
without SCR to allow temporarily greater flexibility to pursue 
compliance strategies other than installation of new controls. This lag 
is permissible consistent with the obligation to eliminate significant 
contribution for reasons that are further discussed in response to 
comments in section VI.B.1.d of this document. However, for any units 
that choose a compliance strategy of installing new SCR controls before 
2030, the daily average emissions rate provisions would apply in the 
second control period of operation. Specification of the second control 
period rather than the first control period provides the unit operators 
with an opportunity to gain operational experience with the new 
equipment before the units will be held to increased allowance-
surrender consequences for exceeding the daily rate.
    The unit-specific daily emissions rate provisions are being 
finalized as proposed except for two changes noted in the previous 
summary: the exclusion from extra allowance surrender requirements of a 
unit's first 50 tons of emissions in a control period exceeding the 
backstop daily rate, and the revision of the starting date for 
implementation of the requirement for units without existing SCR 
controls to 2030 or the second control period of SCR operation, if 
earlier. The rationale for these changes is further discussed in the 
responses to comments later in this section. Additional details of the 
unit-specific daily emissions rate provisions are discussed in section 
VI.B.7 of this document.
ii. Unit-Specific Emissions Limitations Contingent on Assurance Level 
Exceedances
    The second of the trading program enhancements intended to improve 
emissions performance at the level of individual units is the addition 
of unit-specific secondary emissions limitations for units with post-
combustion controls starting with the 2024 control period. The 
secondary emissions limitations will be determined on a unit-specific 
basis according to each unit's individual performance but will 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 percent 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 consists of a prohibition on 
NOX emissions during the control

[[Page 36770]]

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 secondary emissions limitation is in addition to, not in lieu 
of, the primary emissions limitation applicable to each source, which 
continues 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 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 unit-specific 
secondary emissions limitation takes 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 establishing 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, 906-08 (D.C. Cir. 
2008). The EPA's programs to eliminate significant contribution must 
therefore achieve this prohibition, and the evidence of foreseeable and 
avoidable exceedances of the assurance levels demonstrates that EPA's 
existing approach has not been sufficient to accomplish this.
    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 correcting 
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 purpose of the secondary emissions 
limitations is to strengthen the assurance provisions, which apply on a 
statewide, seasonal basis, the unit-specific structure of the new 
limitations will strengthen the incentives for individual units with 
post-combustion controls to maintain their emissions performance at 
levels consistent with their previously demonstrated capabilities. The 
new limitations will strengthen the incentives to operate and optimize 
the controls continuously, which 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 levels. Better emissions performance on average across the ozone 
season by individual units likely will also help address impacts of 
pollution on overburdened communities downwind from some such units. 
See Ozone Transport Policy Analysis Final Rule TSD, Section E.
    The unit-specific secondary emissions limitations are being 
finalized as proposed except that the limitations will apply only to 
units with post-combustion controls. The rationale for this change, and 
additional details regarding the provisions, are discussed in section 
VI.B.8 of this document.
d. Responses to General Comments on the Revisions to the Group 3 
Trading Program
    This section summarizes and provides the EPA's responses to 
overarching comments received on the EPA's proposal to implement the 
emissions reductions required from EGUs under this rule through 
expansion and enhancement of the Group 3 trading program originally 
established in the Revised CSAPR Update, particularly comments on 
electric system reliability. Responses to comments about individual 
aspects of the enhanced trading program are addressed in the respective 
subsections of this section in which those aspects are discussed. 
Responses to comments concerning alleged overcontrol and the EPA's 
legal authority are in sections V.D. and III. Comments not addressed in 
this document are addressed in the separate RTC document available in 
the docket for this action.
    Comment: Some commenters, including EGU owners, states, and several 
RTOs, expressed concern that the requirements for EGUs as formulated in 
the proposal could lead to a degradation in the reliability of the 
electric system. As background, some of these commenters noted that the 
power sector is currently undergoing rapid change, with older and less 
economic fossil-fuel-fired steam generating units retiring while the 
majority of the new capacity being added consists of wind and solar 
capacity. They noted that fossil-fuel-fired generating capacity 
provides reliability benefits not necessarily provided by other types 
of generating capacity, including not only the ability to generate 
electricity in the absence of wind or sunlight, but also inertia, 
ramping capability, voltage support, and frequency response. Commenters 
stated that past EGU retirements and the pace of change in the 
generating capacity mix have already been stressing the electric system 
in some regions, and that the forecasted risk of events where the 
electric system would be unable to fully meet load is rising.
    For purposes of their comments, these commenters generally assumed 
that the rule would lead to additional retirements of fossil-fuel-fired 
generating capacity beyond the retirements that EGU owners have already 
planned and announced. Some of the commenters also suggested that 
remaining fossil-fuel-fired generators would be unwilling to operate 
when needed because allowances might be unavailable for purchase or too 
costly. In the context of an already-stressed electric system, the 
commenters predicted that these assumed consequences of the rule would 
threaten resource adequacy and result in degraded electric reliability. 
To support their assumptions concerning additional retirements, some of 
the commenters pointed to projections of incremental generating 
capacity retirements

[[Page 36771]]

included in the results of modeling performed by the EPA to analyze the 
costs and benefits of the proposed rule. Some commenters indicated that 
they expected EGU owners to be interested in retiring and replacing 
uncontrolled units as of the date of implementation of the backstop 
daily rate requirement on uncontrolled units, and expressed concern 
that the proposal to implement that requirement as of the 2027 control 
period did not allow sufficient time for planning and implementation of 
all the necessary generation and transmission investments to make this 
a viable compliance strategy; for these commenters, 2027 and the 
immediately following years were the period of greatest concern. Some 
commenters appear simply to have assumed that owners of units not 
already equipped with SCR controls would choose to retire the units as 
of the ozone season in which the units would otherwise become subject 
to the backstop daily emissions rate provisions, regardless of whether 
replacement investments had been completed.
    Some of the commenters raising concerns about electric system 
reliability suggested potential modifications to the proposed rule that 
the commenters believed could help address their concerns. The 
suggestions included various mechanisms for suspending some or all of 
the trading program's requirements for certain EGUs at times when an 
RTO or other entity responsible for overseeing a region of the 
interconnected electrical grid determines that generation from those 
EGUs is needed and the EGUs might not otherwise agree to operate. Other 
suggestions focused on ways of providing EGUs with greater confidence 
that allowances would be available to cover their incremental emissions 
during particular events. A number of commenters used the term 
``reliability safety valve,'' in some cases with reference to the types 
of suggestions just mentioned and in other cases without details. Some 
commenters pointed to the ``safety valve'' provision included in the 
Group 2 trading program regulations under the Revised CSAPR Update. 
Another commenter pointed to provisions for a ``reliability safety 
valve'' included in the Clean Power Plan (80 FR 64662, Oct. 23, 2015).
    In addition to offering critiques and recommendations concerning 
the proposed rule's contents, some commenters claimed that the EPA had 
failed to conduct sufficient analysis of the potential implications of 
the proposed rule on electrical system reliability. These commenters 
called on the EPA to consult with RTOs and other entities with 
responsibilities relating to electric system reliability and to perform 
additional analysis. Some commenters advocated for renewed 
consultations and analysis before each planned adjustment to emissions 
budgets under the dynamic budget-setting process. Commenters cited the 
consultation processes followed during implementation of other EPA 
rules, such as the Mercury and Air Toxics Standards (MATS) (77 FR 9304, 
Feb. 16, 2012).
    Response: The EPA disagrees with the comments asserting that this 
rule would threaten resource adequacy or otherwise degrade electric 
system reliability. The emissions reduction requirements for EGUs under 
this rule are being implemented through the mechanism of an allowance 
trading program. Under the trading program, no EGU is required to cease 
operation. The core trading program requirements for a participating 
EGU are to monitor and report the unit's NOX emissions for 
each ozone season period and to surrender a quantity of allowances 
after the end of the ozone season based on the reported emissions. To 
address states' obligations under the good neighbor provision, some 
units of course will have to take some type of action to reduce 
emissions, the actions taken to reduce emissions will generally have 
costs, and some EGU owners will conclude that, all else being equal, 
retiring a particular EGU and replacing it with cleaner generating 
capacity is likely to be a more economic option from the perspective of 
the unit's customers and/or owners than making substantial investments 
in new emissions controls at the unit. However, the EPA also 
understands that before implementing such a retirement decision, the 
unit's owner will follow the processes put in place by the relevant 
RTO, balancing authority, or state regulator to protect electric system 
reliability. These processes typically include analysis of the 
potential impacts of the proposed EGU retirement on electrical system 
reliability, identification of options for mitigating any identified 
adverse impacts, and, in some cases, temporary provision of additional 
revenues to support the EGU's continued operation until longer-term 
mitigation measures can be put in place. No commenter stated that this 
rule would somehow authorize any EGU owner to unilaterally retire a 
unit without following these processes, yet some comments nevertheless 
assume that is how multiple EGU owners would proceed, in violation of 
their obligations to RTOs, balancing authorities, or state regulators 
relating to the provision of reliable electric service. Assumptions of 
this nature are simply not reasonable. Like many commenters, the EPA 
does expect that retirement will be viewed as a more economic 
compliance strategy for some EGUs than installing new controls, but the 
Agency also expects that any resulting unit retirements will be carried 
out through an orderly process in which RTOs, balancing authorities, 
and state regulators use their powers to ensure that electric system 
reliability is protected. The trading program inherently provides ample 
flexibility to allow such an orderly transition to take place. In 
addition, as discussed later in this section, the EPA has adopted 
several changes in the final rule to increase flexibility specifically 
for the early years of the trading program for which commenters have 
indicated the greatest concerns about electric system reliability.
    As an initial matter, the EPA notes two fundamental aspects of this 
rulemaking which together provide a strong foundation for the Agency's 
conclusion that the emissions reductions required from EGUs can be 
achieved with no adverse impacts on electric system reliability. First, 
there is ample evidence indicating that the required emissions 
reductions are feasible. As discussed in section V of this document, 
the magnitude and timing of the EGU emissions reductions required by 
this action reflect application of technologies that are already in 
widespread use, on schedules that are supported by industry experience. 
Second, the required emissions reductions are being implemented through 
the mechanism of a trading program. The enhanced trading program under 
this rule, like the trading programs established by the EPA under prior 
rules, provides EGU owners with opportunities to substitute emissions 
reductions from sources where achieving reductions is cheaper and 
easier for emissions reductions from other sources where achieving 
reductions is more costly or difficult. In general, an EGU owner has 
options to operate the emissions controls identified by the EPA for 
that type of unit (including installation or upgrade of controls where 
necessary), operate other types of emissions controls, or adapt the 
unit's levels of operation to produce less generation if the unit is a 
higher-emitting EGU or more generation if the unit is a lower-emitting 
EGU. The backstop daily emissions rate provisions in this rule reduce 
the degree of available flexibility relative to the degree of 
flexibility in the Agency's

[[Page 36772]]

previous trading programs under CAIR and CSAPR but by no means 
eliminate it. Moreover, even the backstop rate provisions are 
structured as requirements to surrender additional allowances rather 
than as hard limits, providing a further element of flexibility No EGU 
is required to retire or is prohibited from operating at any time under 
this rule. EGUs only need to surrender of the appropriate quantities of 
allowances after the end of the control period.\301\
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    \301\ The EPA has prepared a resource adequacy assessment of the 
projected impacts of the final rule showing that the projected 
impacts of the final rule on power system operations, under 
conditions preserving resource adequacy, are modest and manageable. 
See Resource Adequacy and Reliability Analysis Final Rule TSD, 
available in the docket.
---------------------------------------------------------------------------

    Further, in the large number of comments submitted in this 
rulemaking that assert concerns over electric system reliability, no 
commenter has cited a single instance where implementation of an EPA 
trading program has actually caused an adverse reliability impact. 
Indeed, similar claims made in the context of the EPA's prior trading 
program rulemakings have shown a considerable gap between rhetoric and 
reality. For example, in the litigation over the industry's multiple 
motions to stay implementation of CSAPR, claims were made that allowing 
the rule to go into effect would compromise reliability. Yet in the 
2012 ozone season starting just over 4 months after the rule was 
stayed, EGUs covered by CSAPR collectively emitted below the overall 
program budgets that the rule would have imposed in that year if the 
rule had been allowed to take effect, with most individual states 
emitting below their respective state budgets despite CSAPR not being 
in effect.\302\ Similarly, in the litigation over the 2015 Clean Power 
Plan, assertions that the rule would threaten electric system 
reliability were made by some utilities or their representatives, yet 
even though the Supreme Court stayed the rule in 2016, the industry 
achieved the rule's emissions reduction targets without the rule ever 
going into effect. See West Virginia v. EPA, 142 S. Ct. 2587, 2638 
(2022) (Kagan, J., dissenting) (``[T]he industry didn't fall short of 
the [Clean Power] Plan's goal; rather, the industry exceeded that 
target, all on its own. . . . At the time of the repeal . . . `there 
[was] likely to be no difference between a world where the [Clean Power 
Plan was] implemented and one where it [was] not.' '') (quoting 84 FR 
32561). The claims that these rules would have had adverse reliability 
impacts were proved to be groundless.
---------------------------------------------------------------------------

    \302\ For a state-by-state comparison, see Appendix G of the 
Ozone Transport Policy Analysis Final Rule TSD.
---------------------------------------------------------------------------

    Notwithstanding the long experience confirming the ability of the 
EPA's trading programs to obtain emissions reductions from EGUs without 
impairing the sector's ability to provide reliable electric service, 
the Agency of course does not rely here solely on its experience, but 
has carefully reviewed the comments on this topic for any information 
that might indicate the appropriateness of modifications to the 
enhanced trading program as proposed. In recognition of the important 
role that RTOs play in ensuring electric system reliability, and 
consistent with the requests of some commenters, the EPA has engaged in 
outreach to the RTOs that commented on the proposal to better 
understand their comments specifically and the reliability-related 
comments of other commenters more generally.\303\ Through these 
meetings, the central reliability-related concern was identified as one 
of timing. In order for retirement to be a viable compliance strategy 
for a unit that cannot be entirely spared until replacement investments 
in generation or transmission are completed, it must be possible for 
the unit to operate at critical times for a transition period. Like 
other stakeholders, the RTOs perceived implementation of the backstop 
daily emissions rate provisions on uncontrolled units as materially 
strengthening incentives for such units to either install controls or 
retire. The RTOs were concerned that the option for a coal-fired unit 
without SCR controls to maintain limited operation while surrendering 
allowances at a 3-for-1 ratio for all emissions exceeding the backstop 
daily rate was one that EGU owners would be reluctant to pursue. 
Accordingly, the RTOs expected considerable interest from EGU owners in 
retiring and replacing uncontrolled units as of the date of 
implementation of the backstop daily rate requirement on uncontrolled 
units, and they were concerned that the proposal to implement that 
requirement as of the 2027 control period did not allow sufficient time 
for planning and implementation of all the necessary generation and 
transmission investments to make this a viable compliance strategy. The 
RTOs described their concerns as greatest through approximately the 
2029 control period.
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    \303\ The EPA also met with non-RTO balancing authorities that 
submitted comments. Memoranda identifying the dates, attendees, and 
topics of discussion of these meetings with RTOs and non-RTO 
balancing authorities are available in the docket.
---------------------------------------------------------------------------

    The RTOs also described a concern about potentially illiquid 
allowance markets. They believed it was possible that some EGUs might 
claim an inability to operate at particular times when needed unless 
they had confidence that they would be able obtain additional 
allowances. The RTOs were particularly concerned that introduction of 
dynamic budgeting as proposed would create uncertainty for some EGUs 
regarding the quantities of allowances they would have available for 
use, particularly given the potentially large year-to-year swings if 
budgets were based on historical data from a single year. Some of the 
RTOs suggested potential solutions for these issues, principally in the 
form of auctions or RTO-administered allocations of allowances from 
pools of supplemental allowances, with access to the supplemental 
allowances triggered by certain indications of temporary stress on the 
electric system.
    In the final rule, the EPA is adopting several changes from the 
proposal to help address the reliability-related concerns that were 
identified in comments and brought into greater focus by the 
consultations with the RTOs. The first change adopted in response to 
these comments is that application of the backstop daily NOX 
emissions rate to units without existing SCR controls is being deferred 
until the 2030 control period, or the second control period in which a 
unit operates new SCR controls, if earlier. The purpose of this change 
is to address the concerns that application of the backstop daily 
NOX emissions rate to EGUs without existing SCR starting in 
2027 would provide insufficient time for planning and investments 
needed to facilitate unit retirement as a compliance pathway, which 
some commenters noted they prefer or have already planned. In 
particular, where an EGU owner would prefer to retire and replace an 
uncontrolled EGU rather than to install new controls, and in 
recognition that reliability-related needs may require some degree of 
operation from such units in the period before the investments needed 
to replace the unit can be completed, deferral of the backstop daily 
emissions rate provisions ensures that the necessary generation can be 
provided without being made subject to a 3-for-1 allowance surrender 
ratio that might render that compliance strategy uneconomic compared to 
the faster but less environmentally beneficial compliance strategy of 
installing new controls. The EPA has considered the statutory mandate 
that states' good neighbor obligations--

[[Page 36773]]

including this action's requirement for large coal-fired EGUs to make 
emissions reductions commensurate with good SCR operation--be addressed 
as expeditiously as practicable. The EPA has also considered the fact 
that in this rule, the backstop daily emissions rate serves as a 
supplement to the broader requirement for emissions reductions 
commensurate with application of several control technologies at 
several types of EGUs, encompassing the extent of emissions reductions 
that would be incentivized by the backstop emissions rate requirement. 
The EPA views the backstop daily emissions rate as part of the solution 
to eliminating significant contribution in that it strongly 
incentivizes emissions-control operation throughout each day of the 
ozone season. See sections III.B.1.d, VI.B.1.b, VI.B.1.c.i. For that 
reason, in general we are finalizing the daily backstop emissions rate 
for units that have SCR installed or that install it in the future. It 
is only as an exception to that general rule that we defer the backstop 
daily emissions rate given the transition period and reliability 
concerns identified by commenters. The EPA finds that in this 
circumstance, as long as state emissions budgets continue to reflect 
the required degree of emissions reductions, deferral of the backstop 
rate requirement for uncontrolled units for a transition period can be 
justified on the basis of the greater long-term environmental benefits 
obtained through facilitating the replacement of these affected EGUs 
with cleaner sources of generation. Beginning in the 2030 ozone season, 
all coal-fired EGUs identified for SCR retrofit potential in this 
action will be subject to the backstop daily emissions rate. Any such 
units that remain in operation in that year can and should meet the 
backstop daily emissions rate or be subject to the heightened allowance 
surrender ratio.
    The second change from the proposal adopted in response to the 
reliability-related comments is that the target percentage of the 
states' emissions budgets used to recalibrate the target bank level 
will be set at the proposed 10.5 percent starting in the 2030 control 
period, and for the control periods from 2024 through 2029, a target 
percentage of 21 percent will be used instead. The adoption of the 
higher target percentage for use through the 2029 control period is 
intended to promote greater allowance market liquidity during a period 
of relatively rapid fleet transition about which commenters expressed 
more focused reliability-related needs. As discussed later in this 
section, the EPA expects the introduction of the bank recalibration 
process in 2024 generally to boost market liquidity (by discouraging 
allowance hoarding) and also considers the target percentage of 10.5 
percent set forth in the proposal well supported. Nevertheless, the 
Agency agrees with suggestions by commenters that, at least in the 
early years of the enhanced trading program, a larger bank would 
provide further liquidity and would give program participants greater 
confidence that allowances would be available for purchase when needed. 
Greater confidence by sources would help address RTOs' concern about 
the possibility that some sources could be reluctant to operate if they 
were unsure of their ability to procure allowances to cover their 
emissions. In finding that this modification from proposal is 
appropriate, the EPA has considered the fact that use of a higher 
target percentage will not result in the creation of any additional 
allowances in any control period, because under the recalibration 
provisions, when the total quantity of allowances banked from the 
previous control period is less than the bank target level, the 
consequence is not that additional allowances are created to raise the 
bank to the target level, but simply that no bank adjustment is carried 
out. We also note that while including an annual bank recalibration of 
any percentage is an enhancement in the trading program from prior 
trading programs under the good neighbor provision established in the 
CAIR, CSAPR, CSAPR Update, and Revised CSAPR Update rulemakings, it is 
not unprecedented; the trading program established under the 
NOX SIP Call included ``progressive flow control'' 
provisions that were designed differently from the bank recalibration 
provisions in this rule but had the same purpose and general effect.
    The third change from the proposal adopted in response to the 
reliability-related comments is that the EPA is determining preset 
state emissions budgets not only for the control periods in 2023 and 
2024 as proposed, but also for the control periods in 2025 through 
2029. Finalizing preset state emissions budgets through 2029 will 
establish predictable amounts for the minimum quantities of allowances 
available during the period when commenters have expressed concern that 
the reliability-related need for such predictability is greatest. 
Moreover, the EPA will also determine state emissions budgets using the 
final dynamic budget-setting methodology for the control periods in 
2026 through 2029, and for each state and control period, the dynamic 
budget to be published in the future will only supplant the preset 
budget finalized in this rule for a control period in which that 
dynamic budget is higher than the corresponding preset budget. The 
reason for using dynamic budgets when they are higher than the 
corresponding preset budgets is that the EPA recognizes that evolution 
of the EGU fleet will not follow the exact path projected at the time 
of the rulemaking, and that by not accounting for certain events, the 
preset methodology could result in issuance of smaller quantities of 
allowances than the EPA would find consistent with the quantities of 
emissions from a well-controlled EGU fleet using the dynamic budget-
setting methodology. Events that could cause preset budgets to 
underpredict a state's well-controlled emissions, which are more likely 
in years farther in the future from the time of the rulemaking, include 
deferral of a large EGU's previously planned retirement date or 
increases in electricity demand that outpace the general trend of 
lower-emitting or non-emitting generation replacing higher-emitting 
generation. After considering the commenters' interest in greater 
predictability during the early years of the amended trading program as 
well as the need to protect against instances where the preset budgets 
could underpredict a state's well-controlled emissions in years farther 
from the year of the rulemaking, the EPA finds that the combination of 
these factors justifies the approach of using the higher of the two 
budgets for the control periods from 2026 through 2029.
    In addition to the changes made in response to reliability-related 
comments, several other changes to the proposal being adopted primarily 
for other reasons will also help address the factors identified as 
reliability-related concerns. Most notably, the EPA is adopting changes 
to the dynamic budget computation procedure to incorporate multiple 
years of heat input data, which will reduce year-to-year variability in 
the budgets determined under that procedure and should to some extent 
reduce uncertainty about the quantities of allowances available for use 
in instances where a dynamic budget is being used instead of preset 
budget. In addition, the adoption of a 50-ton threshold before 
application of the 3-for-1 surrender ratio to emissions exceeding the 
backstop daily NOX emissions rate should ensure that no unit 
incurs the higher surrender ratio solely because of unavoidable 
emissions during startup and should help address concerns that some 
units might be reluctant to operate because of the associated 
emissions-

[[Page 36774]]

related costs. Also, the 2026-2027 phase-in of emissions reductions 
commensurate with installation of new SCR controls will increase the 
quantities of allowances available in the 2026 state emissions budgets 
for most states in the trading program.
    To summarize: in light of the strong record supporting the 
feasibility of the emissions reductions required from EGUs; the use of 
a trading program as the mechanism for achieving those emissions 
reductions, with multiple options for achieving compliance and no 
requirements to cease operation of any individual EGU at any time; the 
established processes of RTOs, other balancing authorities, and state 
regulators for managing any EGU retirement requests that do occur in an 
orderly manner with evaluation of potential reliability impacts and 
implementation of mitigation measures where needed; the unbroken, 
decades-long historical success of the EPA's trading programs at 
achieving emissions reductions without any adverse reliability impacts; 
the views expressed by commenters that facilitating EGU retirement and 
replacement as a possible compliance strategy through 2029 would be 
particularly helpful; the changes made in the final rule for control 
periods through 2029 specifically to increase flexibility during this 
transitional period, including deferring application of the backstop 
daily emissions rate provisions for EGUs without existing SCR controls, 
increasing the target percentage used to determine the target allowance 
bank level for purposes of the bank recalibration provisions, and 
establishing preset state emissions budgets which serve as floors 
against potential dynamic budget imposition in those control periods; 
and the changes made in the final rule incorporating multiple years of 
heat input data into the dynamic budget-setting procedure, adding a 50-
ton threshold before application of the 3-for-1 surrender ratio to 
emissions exceeding the backstop daily NOX emissions rate, 
and phasing in emissions reductions requirements commensurate with new 
SCR installations through 2027; the EPA concludes that this action does 
not pose any material risk of adverse impact to electric system 
reliability.
    The EPA has also considered the other suggestions offered by 
commenters for addressing reliability-related issues. With respect to 
suggestions that the rule should include provisions allowing some or 
all of the trading program's requirements to be suspended at times when 
an RTO or other entity with grid management responsibilities determines 
there is a reliability-related need, the EPA again observes that the 
rule's emissions reduction requirements are being implemented through a 
trading program mechanism which makes exceptions of this nature 
unnecessary. Trading programs inherently offer the flexibility to 
accommodate variability in the utilization of individual units. The 
``reliability safety valve'' provisions in the Clean Power Plan, which 
one commenter cited as a precedent to support some form of temporary 
exemption under this rule, in fact was available only in situations 
where a state plan did not allow emissions trading and instead imposed 
unit-specific emissions constraints. See 80 FR 64877-879. Even the 3-
for-1 allowance surrender ratio under the backstop daily NOX 
emissions rate provisions can be met through the surrender of 
additional allowances. The rule does not bar any EGU from operating at 
any time as long as all allowance surrender requirements are met.
    With respect to suggestions that the EPA must undertake recurring 
modeling of the evolving electrical system and consult with RTOs before 
each planned adjustment to emissions budgets, which start from the 
premise that the rule poses risk to electric system reliability that 
must be continuously monitored, the EPA disagrees with the premise and 
therefore also disagrees with the suggestions. As discussed in section 
V of this document, the EPA has taken care to ensure that the emissions 
reduction requirements applicable to EGUs under this rule are feasible 
through application of the control technologies selected as the basis 
of the emissions reductions. The EPA has also performed modeling in 
this rulemaking to assess the benefits and costs of the rule when all 
required emissions reductions are achieved. That modeling, which 
incorporates a representation of electrical grid regions and 
interregional constraints on energy and capacity exchange, affirms the 
feasibility of the overall emissions reduction requirements and is 
illustrative of a control strategy where some units retire and are 
replaced instead of installing new controls. The EPA has also consulted 
with the RTOs (as well as other balancing authorities) in the course of 
this rulemaking to ensure that the EPA understood the concerns 
expressed in their comments such that we could address those comments 
in this final rule. The EPA does not agree that further modeling or 
ongoing consultations with RTOs are needed in advance of the recurring 
dynamic budget adjustments, which do not increase the stringency of the 
rule's emissions reduction requirements established in the final rule. 
The extensive consultation processes adopted by the Agency in 
conjunction with the MATS rulemaking are not a relevant precedent; the 
MATS rule, which was promulgated to address a different statutory 
mandate, was structured in the form of unit-specific emissions 
constraints, fundamentally different from the requirements of this 
rule. The EPA notes that other entities responsible for maintaining 
reliability and managing entry and exit of resources, including the 
North American Electric Reliability Corporation (NERC) and RTOs and 
other balancing authorities, already routinely assess resource adequacy 
and reliability inclusive of meeting all regulatory requirements, 
including environmental requirements.
    While the EPA does not agree that such consultations are a 
necessary precondition for successful implementation of this rule, the 
Agency remains available to engage with any affected EGU or reliability 
authority requesting to meet and discuss the intersection of its power 
sector regulatory programs with electric reliability planning and 
operations. The EPA is also continuing its practice of meeting with the 
U.S. Department of Energy and the Federal Energy Regulatory Commission 
to maintain mutual awareness of how Federal actions and programs 
intersect with the industry's responsibility to maintain electric 
reliability.\304\
---------------------------------------------------------------------------

    \304\ See, e.g., U.S. Department of Energy and U.S. 
Environmental Protection Agency, Joint Memorandum on Interagency 
Communication and Consultation on Electric Reliability (March 8, 
2023), available at https://www.epa.gov/power-sector/electric-reliability-mou.
---------------------------------------------------------------------------

    The EPA is not adopting the suggestion to replicate the so-called 
``safety valve'' mechanism created under the Revised CSAPR Update. That 
mechanism, cited by some commenters as potential precedent for an 
unspecified form of ``reliability safety valve'' in this action, gave 
owners of covered EGUs a one-time opportunity to voluntarily convert 
allowances banked under the Group 2 trading program to allowances 
useable in the Group 3 trading program at an 18-for-1 ratio for use in 
the trading program's initial control period in 2021. See 82 FR 23137-
138. EGU owners chose to use the voluntary mechanism to acquire a total 
of 382 allowances, representing only 0.36 percent of the sum of the 
state emissions budgets and only 0.26 percent

[[Page 36775]]

of the total quantity of allowances available for compliance in that 
control period.\305\ For the 2023 control period, the bank of 
allowances carried over from the 2022 control period plus the 
incremental starting bank that will be created by conversion of 
additional allowances banked under the Group 2 trading program (see 
section VI.B.12.b of this document) will total over 30 percent of the 
full-season emissions budgets.\306\ Given the larger starting bank and 
this rule's bank recalibration provisions (which will be implemented 
starting with the 2024 control period, but which the EPA expects will 
increase allowance market liquidity starting with the 2023 control 
period), the Agency views establishment of a one-time voluntary 
conversion opportunity for the 2023 control period analogous to the 
Revised CSAPR Update's ``safety valve'' provision as unnecessary.
---------------------------------------------------------------------------

    \305\ Additional allowances available for compliance under the 
Group 3 trading program in the 2021 control period included a 
starting allowance bank created through mandatory conversion of a 
portion of the allowances banked under the Group 2 trading program 
as well as supplemental allowances issued to ensure that no 
provisions of the Revised CSAPR Update increasing regulatory 
stringency would take effect before that rule's effective date. See 
86 FR 23133-137.
    \306\ The full-season emissions budgets for the 2023 control 
period under the Group 3 trading program and the incremental 
starting bank created in this action through conversion of 
additional Group 2 allowances (but not the bank of allowances 
carried over from the 2022 control period under the Group 3 trading 
program) will be prorated to reflect the portion of the 2023 ozone 
season occurring after the effective date of this rule. See sections 
VI.B.12.a. and VI.B.12.b.
---------------------------------------------------------------------------

    Finally, in the final rule the EPA is not adopting any of the other 
suggestions concerning additional mechanisms to make additional 
allowances available through auctions or RTO-administered allowance 
pools. For the reasons discussed throughout this section, the EPA 
concludes that the trading program as established in this action 
provides a flexible compliance mechanism that will allow the required 
emissions reductions to be achieved without the need for creation of 
additional allowances. However, the EPA also recognizes the potential 
for allowance market liquidity to be further increased through some 
form of auction mechanism. For instance, it may be appropriate to pair 
the introduction of an auction with a reduction in the bank 
recalibration percentage that begins earlier than 2030. Through a 
supplemental rulemaking, the Agency intends to propose and take comment 
on potential amendments to the Group 3 trading program that would add 
such an auction mechanism to the regulations and make other appropriate 
adjustments in the implementation framework at Step 4.\307\
---------------------------------------------------------------------------

    \307\ Such a rulemaking would not reopen any determinations 
which the Agency has made at Steps 1, 2, or 3 of the interstate 
transport framework in this action. Nor would it reopen any aspects 
of implementation of the program at Step 4 except for those in 
relation to establishing an auction and associated adjustments to 
ensure program stringency is maintained. In this respect, such a 
rulemaking would constitute a discretionary action that is not 
necessary to resolution of good neighbor obligations. Rather, these 
adjustments, if finalized, would reflect a shift from one acceptable 
form of implementation at Step 4 to a slightly modified but also 
acceptable form of implementation at Step 4, as related to EGUs. No 
legal or technical justification for this action as set forth in the 
record here depends on or would be undermined by the development of 
an alternative approach that includes an auction, and if the EPA for 
any reason determines not to propose or finalize such a rulemaking, 
no aspect of this rule would thereby be rendered infeasible or 
incomplete.
---------------------------------------------------------------------------

2. Expansion of Geographic Scope
    In light of the findings at Steps 1, 2, and 3 of the 4-step 
interstate transport framework, the EPA is expanding the geographic 
scope of the existing CSAPR NOX Ozone Season Group 3 Trading 
Program to encompass additional states (and Indian country within the 
borders of such states) with EGU emissions that significantly 
contribute for purposes of the 2015 ozone NAAQS. Specifically, the EPA 
is expanding the Group 3 trading program to include the following 
states and Indian country within the borders of the states: Alabama, 
Arkansas, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, 
Utah, and Wisconsin. Any unit located in a newly added jurisdiction 
that meets the applicability criteria for the Group 3 trading program 
will become an affected unit under the program, as discussed in section 
VI.B.3 of this document.
    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.\308\ 
In contrast, within the 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 meet the program's applicability 
criteria. Issues related to state, tribal, and Federal CAA 
implementation planning authority with respect to sources in Indian 
country in general and in these areas in particular are discussed in 
section III.C.2 of this document. EPA's approach for determining a 
portion of each state's budget for each control period that will 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 VI.B.9 of this document.
---------------------------------------------------------------------------

    \308\ 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 III.C.2.a.
---------------------------------------------------------------------------

    Units within the borders of each newly added state will 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 
necessary is that, as discussed in section VI.B.12.a of this document, 
the effective date is expected to 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--Minnesota, Nevada, and Utah--the sources will 
begin participating in the Group 3 trading program on the 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, Texas, and Wisconsin--the sources will begin participating in 
the Group 3 trading program on May 1, 2023, regardless of the 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 will not substantively affect the sources' 
requirements prior to the rule's effective date. This approach provides 
a simpler transition for the sources historically 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 VI.B.12.a of this document contains further discussion of the 
rationale for this approach and the specific transitional provisions.
    The EPA notes that under the rule, the expanded Group 3 trading 
program will include not only 19 states for which the EPA is 
determining that the required control stringency includes, among other 
measures, installation of new post-combustion controls, but also three

[[Page 36776]]

states--Alabama, Minnesota, and Wisconsin--for which the EPA is 
determining 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, 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 enhancements 
to the design of the trading program, even where states have been 
assigned differing emissions control stringencies. First, the existing 
assurance provisions are being substantially strengthened through the 
addition of the unit-specific secondary emissions limitations discussed 
in sections VI.B.1.c.ii and VI.B.8. Second, by ensuring that individual 
units operate their emissions controls effectively, the unit-specific 
backstop daily emissions rate provisions discussed in sections 
VI.B.1.c.i and VI.B.7 will 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 is 
necessary for sources in Alabama, Minnesota, and Wisconsin to be 
excluded from the revised Group 3 trading program simply because their 
emissions budgets reflect a different selected emissions control 
stringency than the other states in the program.
    The EPA's legal and analytic bases for expansion of the Group 3 
trading program to each of the additional covered states, as well as 
responses to the principal related comments, are discussed in sections 
III, IV, and V of this document, respectively, and responses to 
additional comments are contained in the RTC document. With respect to 
the proposed approach of including all states covered by the rule in a 
single trading program even where the assigned control stringencies 
differ, the only comments received by the EPA supported the approach, 
which is finalized as proposed.
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 applicability 
of this rule to MWCs and cogeneration units outside the Group 3 trading 
program is discussed in sections V.B.3.a and V.B.3.c of this document, 
respectively, and MWC applicability criteria are further discussed in 
section VI.C.6 of this document.
    In this rulemaking, the EPA did not propose and is not finalizing 
any revisions to 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 will 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 additional states where such other 
programs currently are in effect--Alabama, Arkansas, Minnesota, 
Mississippi, Missouri, Oklahoma, Texas, and Wisconsin (including Indian 
country within the borders of such states)--will also become subject to 
the Group 3 trading program.
    In the additional states where other CSAPR trading programs are not 
currently in effect--Nevada and Utah (including Indian country within 
the borders of such states)--units already subject to the Acid Rain 
Program under that program's applicability criteria (see 40 CFR 72.6) 
generally also meet the applicability criteria for the Group 3 trading 
program. 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, 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 the Group 3 trading 
program even if they are not subject to the Acid Rain Program. Using 
data reported to the U.S. Energy Information Administration, in the 
proposal the EPA identified six sources in Nevada and Utah (and Indian 
country within the borders of the states) with a total of 15 units that 
appear to meet the general applicability criteria for the Group 3 
trading program and that do not currently report NOX 
emissions and operating data to the EPA under the Acid Rain Program. 
These units were listed in a table in the proposed rule, and the data 
from that table for these units are reproduced as Table VI.B.3-1 of 
this document. For each of these units, the table shows the estimated 
historical heat input and emissions data that the EPA proposed to use 
for the unit when determining state emissions budgets if the unit was 
ultimately treated as subject to the Group 3 trading program.\309\ The 
EPA requested comment on whether each listed 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 and whether the estimated historical heat input and 
emissions data identified for each unit

[[Page 36777]]

were representative. With respect to the listed units within the 
borders of Nevada or Utah, the EPA received no comments asserting 
either that the units qualified for applicability exemptions or that 
the estimated data identified by the EPA were unrepresentative.\310\ 
For purposes of this rule, the EPA is therefore presuming that the 
units listed in Table VI.B.3-1 do not qualify for applicability 
exemptions and that the estimated data shown in the table for each unit 
are representative. However, the owners and operators of the sources 
retain the option to seek applicability determinations under the 
trading program regulations at 40 CFR 97.1004(c).
---------------------------------------------------------------------------

    \309\ As discussed in section VI.B.10, any unit that becomes 
subject to the Group 3 trading program pursuant to this rule and 
that does not already report emissions data to the EPA in accordance 
with 40 CFR part 75 will not be required to report emissions data or 
be subject to allowance holding requirements under the Group 3 
trading program until May 1, 2024, in order to provide time for 
installation and certification of the required monitoring systems. 
Such a unit will 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.
    \310\ One commenter expressed the view that eight of the listed 
units within Nevada's borders appear to meet the CSAPR applicability 
criteria but provided no comments on the specific proposed data. See 
comments of Berkshire Hathaway Energy, EPA-HQ-OAR-2021-0668-0554, at 
58-59. The EPA also received comments concerning sources within 
Delaware's borders that were included in the proposal's request for 
comment; these comments are moot because Delaware is not being added 
to the Group 3 trading program in the final rule. See comments of 
Calpine, EPA-HQ-OAR-2021-0668-0515; comments of Delaware City 
Refining, EPA-HQ-OAR-2021-0668-0309.

 Table VI.B.3-1--Estimated Data To Be Used for Presumptively Affected Units Within the Borders of Nevada and Utah That Do Not Report Under the Acid Rain
                                                                         Program
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                    Estimated
                                                                                                                    Estimated     ozone season
                              Facility                                                                            ozone season     average NOX
           State                 ID          Facility name              Unit ID                 Unit type          heat input    emissions rate   Notes
                                                                                                                     (mmBtu)        (lb/mmBtu)
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
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. Assoc. 1--  GTA....................  CT....................         660,100          0.0377        1
                                         Garnet Val.
Nevada.....................      54350  Nev. Cogen. Assoc. 1--  GTB....................  CT....................         660,100          0.0387        1
                                         Garnet Val.
Nevada.....................      54350  Nev. Cogen. Assoc. 1--  GTC....................  CT....................         660,100          0.0387        1
                                         Garnet Val.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTA....................  CT....................         749,778          0.0323        1
                                         Black Mtn.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTB....................  CT....................         749,778          0.0370        1
                                         Black Mtn.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTC....................  CT....................         749,778          0.0364        1
                                         Black Mtn.
Nevada.....................      56405  Nevada Solar One......  HI.....................  Boiler................         479,452          0.1667  .......
Nevada.....................      54271  Saguaro...............  CTG1...................  CT....................       1,383,149          0.0314        1
Nevada.....................      54271  Saguaro...............  CTG2...................  CT....................       1,383,149          0.0301        1
Utah.......................      50951  Sunnyside.............  1......................  Boiler................       1,888,174          0.1715  .......
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table notes:
\1\ Unit reports capability of producing both electricity and useful thermal energy.

4. State Emissions Budgets
    In this final rule, the EPA is using a combination of a ``preset'' 
budget calculation methodology and a ``dynamic'' budget calculation 
methodology to establish state emissions budgets for the Group 3 
trading program. A ``preset'' budget is one for which the absolute 
amount expressed as tons per ozone season control period is established 
in this final rule. It uses the latest data currently available on EGU 
fleet composition at the time of this final action. A ``dynamic'' 
budget is one for which the formula and emissions-rate information is 
finalized in this rule, but updated EGU heat input and inventory 
information is used on a rolling basis to set the total tons per ozone 
season for each control period. Both methods of budget calculation are 
designed to set budgets reflective of the emissions control strategies 
and associated stringency levels (expressed as an emissions rate of 
pounds of NOX per mmBtu) identified for relevant EGU types 
at Step 3--which we will refer to in this section as the ``Step 3 
emissions control stringency.'' Preset budgets provide greater 
certainty for planning purposes and can be reliably established in the 
short-term based on known, upcoming changes in the EGU fleet. Due to 
build time for new units and planning and approval processes for plant 
retirements, these major fleet alterations are often known several 
years in advance. This information facilitates presetting budgets that 
appropriately calibrate the identified control stringency to the fleet. 
Dynamic budgets better assure that the budgets remain commensurate with 
the Step 3 emissions control stringency over the longer term, as 
currently unknown changes in the EGU fleet occur. In this final rule, 
in response to comments, we have adjusted the proposal to give a 
greater role for preset budgets through 2029, while dynamic budgeting 
will be phased in to provide greater certainty in the short term and 
allow for a transition period to an exclusively ``dynamic'' approach 
beginning in 2030.
    For the control periods from 2023 through 2025, the preset budgets 
established in the rule will serve as the state emissions budgets for 
the control periods in those years, with no role for dynamic budgeting. 
For the control periods from 2026 through 2029, the EPA is determining 
preset emissions budgets for each control period in the rule and will 
also calculate and publish dynamic budgets for each state in the year 
before each control period using the dynamic budget-setting methodology 
finalized in this rule, applied to data available at the time of the 
calculations. For these four control periods, each state's preset 
budget serves as a floor and may be supplanted by the dynamic emissions 
budget EPA calculates for the state for that control period only if the 
dynamic budget is higher than the preset budget. For control periods in 
2030 and thereafter, the state emissions budgets will be the dynamic 
budgets calculated and published in the year before each control 
period.
    In the dynamic budget calculation methodology, it is the fleet 
composition (reflected by heat input patterns across the fleet in 
service, inclusive of EGU entry and exit) that is dynamic, while the 
emissions stringency finalized in this rule is constant, as reflected 
in

[[Page 36778]]

emissions rates for various types of units. Multiplying the assumed 
emissions rate for each unit (as finalized in this rule) by the 
identified recent historical heat input for each unit and summing the 
results to the state level would provide a given year's state dynamic 
emissions budgets. Dynamic budgets are a product of the formula 
promulgated in this action applied to a rolling three-year average of 
reported heat input data at the state level and a rolling highest-
three-of-five-year average of reported heat input data at the unit 
level. As such, the EPA is confident that dynamic budgets will more 
accurately reflect power sector composition, particularly in later 
years, and certainly from 2030 and beyond, than preset budgets could 
and will therefore better implement the Step 3 emissions control 
stringency over long time horizons.
    Starting in 2025 (for the 2026 control period), the dynamic 
budgets, along with the underlying data and calculations will be 
publicly announced, and this will occur approximately one year before 
the relevant control period begins. These will be published in the 
Federal Register through notices of data availability (NODAs), similar 
to how other periodic actions that are ministerial in nature 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.
    To illustrate how dynamic budgeting will work after the transition 
from preset budgets, the dynamic budgets for the 2030 ozone season 
control period will be identified by May 1, 2029, using the latest 
available average of three years of reported operational data at that 
time (i.e., the average of 2026-2028 heat input data at the state level 
and 2024-2028 years of rolling data at the unit level) applied in a 
simple mathematical formula finalized in this rule, which multiplies 
this heat input data by the emissions rates quantified in this rule. 
Therefore, if a unit retires before the start of the 2028 ozone season 
but had not announced its upcoming retirement at the time of this 
rule's finalization, the dynamic budget approach ensures that the 
dynamic budgets for 2030 and subsequent control periods would represent 
the identified control stringency applied to a fleet reflecting that 
retirement.
    The two examples discussed next illustrate the implementation of 
the dynamic budget during the 2026-2029 time period. During this 
period, the state emissions budget for each state for a given control 
period will be the preset state emissions budget unless the dynamic 
budget is higher. This approach accommodates scenarios where baseline 
fossil heat input may exceed levels anticipated by EPA in the preset 
budgets (e.g., this could result from greater electric vehicle 
penetration rates). Table VI.B.4-1 illustrates this scenario. In the 
preset budget approach for 2028, the 2028 heat input is estimated based 
on the latest available heat input data at the time of rule proposal 
(i.e., 2021; see the subsection on preset budget methodology later in 
this section), which cannot reflect a subsequent change in fleet heat 
input values (column 2) due to, e.g., increased utilization to meet 
increased electric load. However, the dynamic budget would use 2022-
2026 heat input values at the unit level and 2024-2026 heat input 
values at the state level--as opposed to 2021 heat input values--as the 
latest representative values to inform the 2028 state emissions budget. 
Therefore, the heat input values in column 2 under the dynamic scenario 
reflect the change in fleet utilization levels, and when multiplied by 
the emissions rates reflecting the Step 3 emissions control stringency 
in this final rule, the corresponding emissions (18,700 tons) summed in 
column 4 constitute a state budget that more accurately reflects the 
Step 3 emissions control stringency applied to the fleet composition 
for that year, as opposed to the 17,000 tons identified in the preset 
budget approach. As illustrated in the example, the dynamic variable is 
the heat input variable, which changes over time. In this instance, the 
dynamic budget value of 18,700 tons would be implemented for 2028 
instead of the preset value, and thus accommodate the unforeseen 
utilization changes in response to higher demand.
    In the second table, Table VI.B.4-2, the dynamic budget is lower 
than the preset budget due to retirements that were not foreseen at the 
time the preset budgets were determined. In the preset budget approach 
for 2028, the 2028 heat input is still estimated based on the latest 
available heat input data at the time of rule proposal (i.e., 2021), 
which cannot reflect a subsequent fleet change in heat input values due 
to an unanticipated retirement of one of the state's coal-fired units 
before the start of the 2028 ozone season. However, the dynamic budget 
again would use 2022-2026 heat input values at the unit level and 2024-
2026 heat input values at the state level--as opposed to 2021 heat 
input values--as the latest representative values to inform the 2028 
state emissions budget, which would reflect the decline in coal heat 
input and replacement with natural gas heat input (capturing the coal 
unit's retirement). Therefore, the heat input values under the dynamic 
budget scenario reflect the change in fleet composition, and when 
multiplied by the relevant emissions rates reflecting the Step 3 
emissions control stringency identified in this final rule, the 
corresponding emissions (15,000 tons) constitute a state budget that 
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. However, for the 2026-2029 period, in which the EPA 
implements an approach that utilizes the higher of the dynamic budget 
or preset budget, the budget implemented for 2028 in this scenario 
would be the 17,000 ton preset amount.
    During the 2026-2029 transition period--during which substantial, 
publicly announced utility commitments exist for higher emitting units 
to exit the fleet--it is still possible that yet-to-be known, unit-
specific retirements (such as illustrated in this second scenario) may 
result in dynamic budgets that are lower than the preset budgets 
finalized in this rule. However, during this transition period EPA 
believes that having the preset budgets serve as floors for the state 
emissions budgets is appropriate for two primary reasons identified by 
commenters. First, commenters repeatedly emphasized the need for 
certainty and flexibility to successfully carryout plans for 
significant fleet transition through the end of the decade. The 2026-
2029 period is expected to have substantial fleet turnover. Current 
Form EIA-860 data, in which utilities report their retirement plans, 
identify 2028 as the year with the most planned coal capacity 
retirements during the 2023-2029 timeframe. Using preset budgets as 
state emissions budget floors provides states and utilities with 
information on minimum quantities of allowances that can be used for 
planning purposes. In turn, this fosters the operational flexibility 
needed while putting generation and transmission solutions into place 
to accommodate such elevated levels of retirements. Second, the latter 
part of the decade has a significant amount of unit-level firm 
retirements already planned and announced for purposes of compliance 
with other power sector regulations or fulfillment of utility 
commitments. These known retirements are already

[[Page 36779]]

captured in the preset state budgets, with the result that the 
likelihood and magnitude of instances where a state's dynamic budget 
for a given control period would be lower than its preset budget for 
the control period is reduced in this 2026-2029 period relative to 
control periods further in the future for which retirement plans have 
not yet been announced. After 2029, the dynamic budgets from 2030 
forward will fully capture all prior retirements and new builds when 
the fleet is entering this period where unit-specific data on such 
plans is less frequently available. For instance, through the remaining 
portion of the decade, the amount of coal steam retirements identified 
and reported through Form EIA-860 is nearly 7 GW each year. However, 
for the decade beginning in 2030--the amount of capacity currently 
reported with a planned retirement is less than 2 GW each year.\311\ 
This yet-to-be available data and relative lack of currently known firm 
retirement plans for 2030 and beyond make dynamic budget implementation 
for those years essential for state emissions budgets to maintain the 
Step 3 control stringency required under this rule.
---------------------------------------------------------------------------

    \311\ See 2021 Form EIA Form 860--Schedule 3, Generator Data. 
Department of Energy, Energy Information Administration.

                       Table VI.B.4-1--Example of Preset and Dynamic Budget Calculation in Scenario of Increased Fossil Heat Input
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Preset budget approach (2028)              Dynamic budget approach (2028)
                                                                  --------------------------------------------------------------------------------------
                                                                                   Preset       Preset tons                                 Tons (heat
                                                                   Preset heat    emissions    (heat input x    Heat input    Emissions       input x
                                                                      input       rate (lb/   emissions rate)/    (tBtu)      rate (lb/      emissions
                                                                      (tBtu)       mmBtu)           2000                       mmBtu)       rate)/2000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Units.......................................................          600          0.05          15,000           660          0.05          16,500
Gas Units........................................................          400          0.01           2,000           440          0.01           2,200
                                                                  --------------------------------------------------------------------------------------
    State Budget (tons)..........................................  ...........  ............          17,000   ...........  ............          18,700
--------------------------------------------------------------------------------------------------------------------------------------------------------


                        Table VI.B.4-2--Example of Preset and Dynamic Budget Calculation in Scenario of Unanticipated Retirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Preset budget approach (2028)              Dynamic budget approach (2028)
                                                                  --------------------------------------------------------------------------------------
                                                                                   Preset       Preset tons                                 Tons (heat
                                                                   Preset heat    emissions    (heat input x    Heat input    Emissions       input x
                                                                      input       rate (lb/   emissions rate)/    (tBtu)      rate (lb/      emissions
                                                                      (tBtu)       mmBtu)           2000                       mmBtu)       rate)/2000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Units.......................................................          600          0.05          15,000           500          0.05          12,500
Gas Units........................................................          400          0.01           2,000           500          0.01           2,500
                                                                  --------------------------------------------------------------------------------------
    State Budget (tons)..........................................  ...........  ............          17,000   ...........  ............          15,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In summary, for the control periods in 2023 through 2025, EPA is 
providing only preset budgets in this final rule because those control 
periods are in the immediate future and would not substantially benefit 
from the use of future reported data. For these years, the certainty 
around new builds and retirements is higher than ensuing years. For the 
ozone season control periods of 2026 through 2029, EPA is providing 
both preset budgets in this final rule and dynamic budgets via future 
ministerial actions. For those control periods from 2026 through 2029, 
the preset budgets finalized in this rule serve as floors, such that a 
given state's dynamic budget ultimately calculated and published for 
that control period will apply to that state's affected EGUs only if it 
is higher than the corresponding preset budget finalized in this 
rulemaking. This approach is in response to stakeholder comments 
requesting more advance notice regarding the total quantities of 
allowances available to accommodate compliance planning through the 
latter half of the decade, during a period of particularly high fleet 
transition expected with or without this rulemaking.
    EPA's emissions budget methodology and formula for establishing 
Group 3 budgets are described in detail in the Ozone Transport Policy 
Analysis Final Rule TSD and summarized later in this section.
a. Methodology for Determining Preset State Emissions Budgets for the 
2023 Through 2029 Control Periods
    To compose preset state emissions budgets, the EPA is using the 
best available data at the time of developing this final rule regarding 
retirements and new builds. The EPA relies on a compilation of data 
from Form EIA-860 (where facilities report their future retirement 
plans), the PJM Retirement Tracker, utilities' integrated resource 
plans, notification of compliance plans with other EPA power sector 
regulatory requirements, and other information sources that EPA 
routinely canvasses to populate the data fields included in the 
Agency's NEEDS database. The EPA has updated this data on retirements 
and new builds using the latest information available from these 
sources at the time of final rule development as well as input provided 
by commenters.
    For determining preset state emissions budgets, the EPA generally 
uses historical ozone season data from the 2021 ozone season, the most 
recent data available to EPA and to commenters responding to this 
rulemaking's proposal and providing a reasonable representation of 
near-term fleet conditions. This is similar to the approach taken in 
the CSAPR Update and the Revised CSAPR Update, where

[[Page 36780]]

the EPA likewise began with data for the most recent ozone season at 
the time of proposal (2015 and 2019, respectively).
    By using historical unit-level NOX emissions rates, heat 
input, and emissions data in the first stage of determining preset 
emissions budgets, the EPA is grounding its budgets in the most recent 
representative historical operation for the covered units at the time 
EPA began its final rulemaking. This data set is a reasonable starting 
point for the budget-setting process as it reflects recent publicly 
available and quality assured data reported by affected facilities 
under 40 CFR part 75, largely using CEMS. 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 first step in deriving the future year state emissions budget 
is to calibrate historical data to planned future fleet conditions. EPA 
does this by adjusting this historical baseline information to reflect 
the known changes (e.g., when deriving the 2023 state emissions budget, 
EPA starts by adjusting 2021 unit-level data to reflect changes 
announced and planned to occur by 2023). The EPA adjusted the 2021 
ozone-season data to reflect committed fleet changes expected to occur 
in the baseline. This includes announced and confirmed retirements, new 
builds, and retrofits that occur after 2021 but prior to 2023. For 
example, if a unit emitted in 2021, but retired prior to May 1, 2022, 
its 2021 emissions would not be included in the 2023 baseline estimate. 
For units that had no known changes, the EPA uses the actual emissions, 
heat input, and emissions rates reported for 2021 as the baseline 
starting point for calculating the 2023 state emissions budgets. 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).
    The second step in deriving the preset state emissions budgets is 
for EPA to take the adjusted historical data from Step 1, and adjust 
the emissions rates and mass emissions to reflect the control 
stringencies identified as appropriate for EGUs of that type. For 
instance, if an SCR-equipped unit was not operating its SCR so as to 
achieve a seasonal average emissions rate of 0.08 lb/mmBtu or less in 
the historical baseline, the EPA lowered that unit's assumed emissions 
rate to 0.08 lb/mmBtu and calculated the impact on the unit's mass 
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. The improved emissions rate of 0.08 lb/mmBtu is 
applied to this constant heat input, reflecting control optimization. 
In this manner, the unit-level totals from Step 1 are adjusted to 
reflect the additional application of the assumed control technology at 
a given control stringency. This is illustrated in Table VI.B.4.a-1. 
Row 1 reflects the 2021 historical data for this SCR-controlled unit. 
Row 2 reflects no change (as there are no known changes such as planned 
retirement or coal-to-gas conversion). Row 3 reflects application of 
the Step 3 stringency (i.e., a 0.08 lb/mmBtu emissions rate from SCR 
optimization). The resulting impact on emissions is a reduction from 
the historical 4,700 tons to an expected future level of 615 tons. A 
state's preset budget for a given control period is the sum of the 
amounts computed in this manner for each unit in the state for the 
control period.

         Table VI.B.4.a-1--Example of Unit-Level Data Calculations for Deriving State Emissions Budgets
----------------------------------------------------------------------------------------------------------------
                                                                    Heat input     Emission rate     Emissions
                                                                      (tBtu)        (lb/mmBtu)        (tons)
----------------------------------------------------------------------------------------------------------------
Historical Data (2021)..........................................          15.384            0.61           4,700
Step 1 (Baseline)--Historical data adjusted for planned changes.          15.384            0.61           4,700
Step 2--Baseline further adjusted for Step 3 stringency.........          15.384            0.08             615
----------------------------------------------------------------------------------------------------------------

    For each control period from 2026 onward, the unit-specific 
emissions rates assumed for all affected states except Alabama, 
Minnesota, and Wisconsin 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 Final Rule 
TSD. The emissions rates assigned to large coal-fired EGUs for 2026 
state emissions budget computations only reflect 50 percent of the SCR 
retrofit emissions reduction potential at each of those units, to 
capture the phase-in approach EPA is taking for this control as 
described in section VI.A of this document. The EPA calculates these 
unit-level emissions rates in 2026 as the sum of the unit's baseline 
emissions rate and its controlled emissions rate divided by two (i.e., 
50 percent of the emissions reduction potential of that pollution 
control measure). The emissions rates assigned to these large coal-
fired EGUs for 2027 state emissions budget computations reflect the 
full assumed SCR retrofit emissions potential at those units, by 
applying the controlled emissions rate only. For example, a coal steam 
unit greater than or equal to 100 MW currently lacking a SCR and 
emitting at 0.20 lb/mmBtu would be assumed to reduce its emissions rate 
to 0.125 lb/mmBtu rate in 2026 and 0.050 lb/mmBtu rate in 2027 for 
purposes of deriving its preset state emissions budgets in those years.
    Comment: Some commenters suggested that EPA should not reflect 
planned retirements in its preset budgets. The suggestion stems from 
commenters' observation that those retirement decisions may yet change.
    Response: The effectiveness of EPA's future year preset state 
emissions budgets depends on how well they are calibrated to the 
expected future fleet. Therefore, EPA believes it is important to 
incorporate expected new builds, retirements, and unit changes already 
slated to occur. Ignoring these factors would dilute, rather than 
strengthen, the ability of preset budgets to capture the most 
representative fleet of EGUs to which they will be applied. Omitting 
scheduled retirements and new builds from state emissions budgets would 
reflect units that power sector operators and planning authorities do 
not expect to exist, while failing to reflect units that are expected 
to exist.
    EPA notes it is using the best available data at the time of the 
final rule. EPA relies on a compilation of data from Form EIA-860 where 
facilities report their future retirement plans. In addition, EPA is 
using data from regional transmission organizations who are cataloging, 
evaluating, and approving such retirement plans and data; data from 
notifications submitted directly to EPA by the utility themselves

[[Page 36781]]

through comments; and retirement notifications submitted to permitting 
authorities. This information is highly reliable, real-world 
information that provides EPA with the high confidence that such 
retirements will in fact occur.
    If a unit's future retirement does not occur on the currently 
scheduled date, EPA observes that such an unexpected departure from the 
currently available evidence would still not undermine the ability of 
affected EGUs to comply with their applicable state budgets. EPA's 
approach of using historical data and incorporation only of announced 
fleet changes in estimating its future engineering analytics baseline 
means that its future year baseline generation and retirement outlook 
for higher emitting sources is more likely to understate future 
retirements (rather than overstate as suggested by commenter), as EPA 
does not assume for the purpose of preset budget quantification any 
retirements beyond those that are already planned. In other words, in 
the 2023 through 2029 timeframe for which EPA is establishing preset 
state emissions budgets in this rulemaking, there are more likely to be 
additional future EGU retirements beyond those scheduled prior to the 
finalization of this rule than there are to be reversed or 
substantially delayed changes to already announced EGU retirement 
plans. For instance, subsequent to the EPA's finalization of the 
Revised CSAPR Update Rule budgets for 2023 (rule finalized in March 
2021), the owners of Sammis Units 5-7 and Zimmer Unit 1 in Ohio 
(totaling nearly 3 GW of coal capacity) announced that the units would 
retire by 2023--nearly 5 years earlier than previously 
planned.312 313 These coal retirements were not captured in 
Ohio's 2023 or 2024 state emissions budgets established under the 
Revised CSAPR Update. Meanwhile, there have been no announcements of 
previously announced retirement plans being rescinded or delayed for 
other Ohio units. Similarly, the Joppa Power Plant in Illinois 
accelerated its retirement from 2025 to 2022 shortly after the Revised 
CSAPR Update Rule was signed.\314\
---------------------------------------------------------------------------

    \312\ Available at https://www.prnewswire.com/news-releases/energy-harbor-transitions-to-100-carbon-free-energy-infrastructure-company-in-2023-301501879.html.
    \313\ Available at https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/coal/071921-vistra-plans-to-retire-13-gw-zimmer-coal-plant-in-ohio-five-years-early.
    \314\ Available at https://www.prnewswire.com/news-releases/joppa-power-plant-to-close-in-2022-as-company-transitions-to-a-cleaner-future-301263013.html.
---------------------------------------------------------------------------

    We further observe that the commenters' concern is only materially 
meaningful for the 2023 through 2025 preset budget periods, where the 
currently known information is generally the most reliable. For the 
2026-2029 control periods, if an anticipated fleet change such as an 
EGU retirement does not actually occur, the dynamic budget setting 
methodology would, all else being equal, generate a budget reflective 
of that unit's continued operation (as the budget would be based on the 
preceding years of historical data), and that dynamic budget will 
supplant the preset budget for that state (if it represents a total 
quantity of emissions higher than the preset budget).
    Because the future is inherently uncertain, all analytic tools and 
information resources used in any estimation of future EGU emissions 
will yield some differences between the projected future and the 
realized future. Such potential differences may either increase or 
decrease future emissions in practice, and the unavoidable existence of 
such differences does not, on its own, render the EPA's inclusion of 
currently announced retirements an unreasonable feature of the 
methodology for determining future year preset emissions budgets. To 
the contrary, if the EPA failed to include these announced retirements, 
the rule would knowingly authorize amounts of additional, sustained 
pollution that are not currently expected to occur. If those 
retirements largely or entirely occur as currently scheduled, the 
overestimated state budgets would allow other EGUs to emit additional 
pollution in place of the emissions from the retired EGUs instead of 
maintaining or improving their emissions performance to eliminate 
significant contribution with nonattainment and interference with 
maintenance of the NAAQS.\315\
---------------------------------------------------------------------------

    \315\ Some of these announced retirements reflect the operator's 
reported intention to EPA to retire the affected capacity by that 
time as part of their compliance with effluent limitation guidelines 
or with the coal combustion residuals rule.
---------------------------------------------------------------------------

    Additionally, as noted elsewhere, EPA's use of a market-based 
program, a starting bank of converted allowances, and variability 
limits are all features that will readily accommodate whatever 
relatively limited differences in emissions may occur if a currently 
scheduled EGU retirement is ultimately postponed during the preset 
budget years of 2023 through 2025. Therefore, EPA's resulting preset 
state emissions budgets--inclusive of expected fleet turnover--are 
robust to the inherent uncertainty in future year baseline conditions 
for the period in which they are applied.
    Comment: Some commenters suggested that EPA should use a multi-year 
baseline for all of its state budget derivations, including preset 
budgets, to control for outlier years that may not be representative of 
future years due to major weather events or other fleet disruptions 
(such as a large nuclear unit outage).
    Response: For preset state emissions budget derivation, EPA is 
finalizing use of the same single-year \316\ historical baseline 
approach it used in the proposed rule. This approach is similar to the 
Revised CSAPR Update, where EPA also relied on a single-year historical 
baseline to inform its Step 3 approach. EPA's interest in a historical 
data set to inform this part of the analysis is to capture the most 
representative view of the power sector. For estimating preset state 
budgets, EPA finds that, particularly at the state level, more recent 
data is a better representation and basis for future year baselines 
rather than incorporating older data. Taking as an example preset 
budget estimation for the 2023 through 2025 ozone seasons, the EPA is 
able to compare its single-year base line to an alternative multi-year 
baseline (e.g., a 3-year baseline encompassing 2020-2022) and determine 
that the single year baseline better reflects future fleet operation 
expectation than a multi-year baseline that incorporates units which 
have since retired as well as outlier patterns in load during pandemic-
related shutdowns.
---------------------------------------------------------------------------

    \316\ For the purposes of this rulemaking, when describing a 
``year'' or ``years'' of data utilized in state emission budget 
computations, the EPA is actually utilizing the relevant data from 
May 1 through September 30 of the referenced year(s), consistent 
with the control period duration of this rule's EGU trading program.
---------------------------------------------------------------------------

    EPA recognizes that 2021 is the latest available historical data as 
of the preparation of this rulemaking, and therefore the most up-to-
date picture of the fleet at the time EPA began its analysis. EPA then 
further evaluates the 2021 historical data at the state level to 
determine whether it was a representative starting point for estimating 
future year baseline levels and subsequently deriving the preset state 
emissions budgets. If the Agency finds any state-level anomalies, it 
makes necessary adjustments to the data. While unit-level variation may 
occur from year-to-year, those variations are often offset by 
substitute generation from other units within the state. Therefore, EPA 
conducts its first screening at the state level by identifying any 
states where 2021 heat

[[Page 36782]]

input and 2021 emissions were the lowest year for heat input and 
emissions relative to the past several years (2018-2022, excluding 2020 
due to shut downs and corresponding reduced utilization related to the 
pandemic onset).317 318 Then, for that limited number of 
states (AL, LA, MS, and TX) in which 2021 reflects the minimum fossil 
fuel heat input and minimum emissions over the baseline evaluation 
period, EPA--similar to prior rules--evaluated whether any unit-level 
anomalies in operation were driving this lower heat input at the state 
level. EPA examined unit-level 2021 outages to determine where an 
individual unit-level outage might yield a significant difference in 
state heat input, corresponding emissions baseline and resulting state 
emissions budgets. When applying this test to all of the units in the 
previously identified states (and even when applying to EGUs in all 
states for whom Federal implementation plans are finalized in this 
rulemaking), the EPA determined that the only unit with a 2021 outage 
that (1) decreased its output relative to preceding or subsequent years 
by 75 percent or more (signifying an outage), and (2) could potentially 
impact the state's emissions budget substantially as it constituted 
more than 5 percent of the state's heat input in a non-outage year was 
Daniel Unit 2 in Mississippi. EPA therefore adjusted this state's 
baseline heat input and NOX emissions to reflect the 
operation of this unit based on its 2019 data--which was the second 
most recent year of data available at the time of proposal (excluding 
2020 given atypical impacts from pandemic-related shutdowns) for which 
this unit operated. The EPA then applied the Step 3 mitigation 
strategies as appropriate to this unit (i.e., combustion controls 
upgrade in 2024, SCR retrofit in 2026/2027) to derive this portion of 
Mississippi's budget. This test, and subsequent adjustment as 
necessary, enables EPA to utilize the latest, most representative data 
in a manner that is robust to any substantial state-level or region-
level outlier events within that dataset and further validates EPA's 
comprehensive approach to using the most recent single year of data for 
preset budgets.
---------------------------------------------------------------------------

    \317\ EPA identified states for which 2021 both heat input and 
emissions were the low year among the examined baseline period as a 
preliminary screen to identify potential instances where reduced 
utilization may lead to an understated emissions baseline value.
    \318\ EPA also conducted a similar test to identify states in 
which 2021 heat input and emissions were the high year among the 
examined baseline period and found that it was for both Utah and 
Pennsylvania. However, for both states the elevated heat input trend 
persisted into 2022 (at slightly lower levels and was correlated 
with retirements elsewhere in the region--indicating that some of 
this heat input increase may be representative of the future fleet 
and that planned retirements factored into preset budget will remove 
any unrepresentative heat input from 2021.
---------------------------------------------------------------------------

b. Methodology for Determining Dynamic State Emissions Budgets for 
Control Periods in 2026 onwards
    In this final rule, the EPA is finalizing an approach of using 
multi-year baseline data for purposes of dynamic budget computation. 
The aforementioned testing of the representative nature of a single 
year of baseline data for purposes of preset budget setting is not 
possible in the dynamic budget process as that data will not be 
available until a later date. Further, the EPA generally agrees with 
commenters that use of a multi-year period will be more robust to any 
unrepresentative outlier years in fleet operation and thus better 
suited for purposes of dynamic budgets. The methodology for determining 
dynamic state emissions budgets for later control periods (2026 and 
beyond) relies on a nearly identical methodology for applying unit-
level emissions rate assumptions as the preset budget methodology. But 
it uses more recent heat input data that will become available by that 
future time, employing a multi-year approach for identifying the heat 
input data so as to ensure representativeness.
    For dynamic budgets, EPA uses more years of baseline data to 
control for any state-level and unit-level variation that may occur in 
a future single year that is not possible to identify at present. 
First, for each unit operating in the most recent ozone season for 
which data have been reported, EPA identifies the average of the three 
highest unit-level heat input values from the five ozone seasons ending 
with that ozone season to get a representative unit-level heat input. 
Ozone seasons for which a unit reported zero heat input are excluded 
from the averaging of the three highest heat input values for that 
unit. These representative unit-level heat input values established for 
each unit individually are then summed for all units in each state. 
Each unit's representative unit-level heat input is then divided into 
this state-level sum to get that unit's representative percent of the 
aggregated average heat input values for all affected EGUs in that 
state.
    Next, EPA calculates a representative state-level heat input by 
taking the average state-level total heat input across affected EGUs 
from the most recent three ozone seasons for which data have been 
reported, to which the above-derived representative unit-level 
percentages of heat input are applied. The EPA uses a three-year 
baseline period for state-level heat input versus the five-year 
baseline period noted previously for unit-level heat input because 
there is less variation from year to year at the state level compared 
to the unit level. Multiplying the representative unit-level 
percentages of heat input by the representative state-level heat input 
yields a normalized unit-level heat input value for each affected EGU. 
This step assures that the total heat input being reflected in a 
dynamic state budget does not exceed the average total heat input 
reported by affected EGUs in that state from the three most recent 
years. Finally, each normalized unit-level heat input value is 
multiplied by the emissions rate reflecting the assumed unit-specific 
control stringency for each particular year (determined at Step 3) to 
get a unit-level emissions estimate. These unit-level emissions 
estimates are then summed to the state level to identify the dynamic 
budget for that year. This procedure to derive normalized unit-level 
heat input is captured in the following table:

                                            Table VI.B.4.b-1--Derivation of Normalized Unit-Level Heat Input
                                                                     [Illustrative]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Representative unit-                      Representative state
                                2022     2023     2024     2025     2026     level heat input     Representative   level heat input (avg 3   Normalized
                                Heat     Heat     Heat     Heat     Heat   (avg of 3 highest of     unit-level        most recent state      unit--level
                               input    input    input    input    input          past 5)             percent              totals)           heat input
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit A......................      100      200      150      200      300                   233               41%                      483           199
Unit B......................       50      100      200       50      100                   133                24                      483           114
Unit C......................      250      150      150      200      100                   200                35                      483           170
                             ---------------------------------------------------------------------------------------------------------------------------

[[Page 36783]]

 
    State Total.............      400      450      500      450      500                   567  ................  .......................  ............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The EPA will issue these dynamic budget quantifications 
approximately 1 year before the relevant control period. We view such 
actions as ministerial in nature in that no exercise of agency 
discretion is required. For instance, starting in early 2025, the EPA 
would take the most recent three years of state-level heat input data 
and the most recent five years of unit-level heat input data and 
calculate 2026 state emissions budgets using the methodology described 
previously. For 2026-2029, EPA is establishing the preset state 
emissions budgets finalized in this rulemaking and will only supplant 
those preset emissions budgets with the to-be-published dynamic 
emissions budgets if, for a given state and a given control period, 
that dynamic budget yields a higher level of emissions than the 
corresponding preset budget finalized in this rulemaking. For 2030 and 
beyond, the EPA solely uses the dynamic budget process.
    By March 1 of 2025, and each year thereafter, the EPA will make 
publicly available through a NODA the preliminary state emissions 
budgets for the subsequent control period and will provide stakeholders 
with a 30-day opportunity to submit any objections to the updated data 
and computations. (This process will be similar to the releases of data 
and preliminary computations for allocations from new unit set-asides 
that is already used in existing CSAPR trading programs.) By May 1 of 
2025, and each year thereafter, the EPA will publish the dynamic 
budgets for the ozone-season control period in the following calendar 
year. Through the 2029 ozone season control period, these budgets will 
only be imposed if the applicable dynamic state budget is higher than 
the corresponding preset state budget finalized in this rulemaking. 
Preliminary and final unit-level allowance allocations for the units in 
each state in each control period will be published on the same 
schedule as the dynamic budgets for the control period. For the control 
periods from 2026 through 2029, the allocations will reflect the higher 
of the preset or dynamic budget for each state, and after 2030, the 
allocations will reflect the dynamic budgets. Additional details, 
corresponding data and formulas, and examples for the dynamic budget 
are described in the Ozone Transport Policy Analysis Final Rule TSD.
    Comment: Multiple commenters claimed that designing a dynamic 
budget process that relies on a single year of yet-to-be known heat 
input data may produce an unrepresentative view of fleet operations for 
the immediate ensuing years. Commenters pointed to the hypothetical of 
another pandemic-like year (e.g., 2020) occurring in the future, noting 
that 2020 would have been a poor choice for estimating 2022 fleet 
operation and the same would likely hold true if a similar event 
occurred, for example, in 2025--that would consequently make that year 
a poor choice as a representative of 2027 baseline. They further 
pointed out that severe weather events and operating disruptions (a 
large nuclear plant outage) can similarly render a single year baseline 
a risky choice to inform future expectations.
    Response: Insofar as the commenters are addressing the reference 
period for dynamic budget computation regarding years of data that have 
not yet occurred and therefore not currently available for evaluating 
their representative nature, EPA agrees and is incorporating a rolling 
3-year baseline at the state level and a rolling 5-year baseline at the 
unit level for determining dynamic budgets in this final rule. These 
multi-year rolling baseline (or reference periods) will minimize any 
otherwise undue impact from individual years where fleet-level or unit-
level heat input was uncharacteristically high or low. EPA determined 
that such an approach, while not needed for preset budgets, is 
necessary in the case of dynamic budgets because the baseline in that 
instance is occurring in a future year and therefore is not knowable 
and available to test for representativeness at the time of the final 
rule. To control for this type of uncertainty, the EPA finds it 
appropriate to use a multi-year baseline in this instance per commenter 
suggestion. While a multi-year baseline may have a slight drawback of 
using a slightly more dated past fleet performance (including emissions 
from higher emitting EGUs that may have subsequently reduced 
utilization by the target year for which the dynamic budget is being 
calculated) to estimate the expected future fleet performance at the 
emissions performance levels determined by the Step 3 result in this 
rulemaking, that drawback is worth the advantage of protecting against 
instances where atypical circumstances in the most recent single year 
may occur and not be representative of the subsequent year for which 
the dynamic budget is being estimated. This singular drawback of moving 
to a multi-year baseline is most pronounced in the early years of 
dynamic budgeting. Therefore, EPA is able to lessen the impact of this 
drawback of the multi-year baseline by extending the earliest start 
date of dynamic budgets from 2025 (as proposed) to 2026 in the final 
rule.
    Comment: Commenters suggested that the dynamic budget procedure 
would not provide enough advance notice of state budget and unit level 
allocation for sources to adequately plan future year operation.
    Response: EPA disagrees with the notion that the timing of the 
dynamic budget determination would occur too close to the control 
period to allow adequate operations planning for compliance. As 
described previously, the dynamic budget level would be provided 
approximately 1 year in advance of the start of the control period 
(i.e., around May 1), and the allowance allocations would occur on July 
1, approximately 10 months prior to the start of the compliance period. 
Not only is this an adequate amount of time as demonstrated by the 
successful implementation of past rules that have been finalized and 
implemented within several months of the beginning of the first 
affected compliance period (e.g., Revised CSAPR Update), but EPA notes 
it is maintaining similar trading program flexibility and banking 
flexibilities of past programs which provide further opportunities for 
sources to procure allowances and plan for any future operating 
conditions. Finally, as noted previously, the EPA is providing preset 
budgets for the years 2023-2029, which serve as an effective floor on 
the state's ultimate emissions budget level for years 2026-2029, as

[[Page 36784]]

states will receive the higher of the preset or dynamic budget for 
those years. This provision of certain preset state emissions budgets 
serving as a floor level for 2026-2029 should further assuage 
commenters' concerns regarding planning certainty about allowance 
allocations and state emissions budget levels during this period of 
power sector transition to cleaner energy sources.
    Comment: Commenters raised concerns that there is a two-year lag in 
the dynamic budgets in that, for example, for the dynamic budget in the 
2026 control period, the calculations will be based on heat input and 
inventory information reflective of data through 2024. Commenters 
contend that, if there is a much greater need for allowances for 
compliance due to unavoidable or unforeseen need for a higher amount of 
heat input than reflected in prior years' data, the budget for that 
control period will not reflect this need, and the allowances will only 
become available when the dynamic budget is calculated using that 
information (i.e., 2025 data would be reflected starting in the 2027 
dynamic budget). According to commenters, this lag could present a 
serious compliance challenge. Other commenters raised a concern in the 
opposite direction about the potential ``slack'' created by the lag 
time--meaning that as high-emitting units retire, their emissions and 
operation will still inform the state emissions budgets for additional 
years beyond their retirement due to the lag.
    Response: The EPA recognizes there will be a data lag inherent in 
the computation of future year dynamic emissions budgets, because the 
dynamic budgets will reflect fleet composition and utilization data 
from recent previous control periods rather than the control periods 
for which the dynamic budgets are being calculated. This means that the 
resulting dynamic budgets will reflect a limited lag behind the actual 
pace of the EGU fleet's trends. However, on the whole, those trends are 
clearly toward more efficient and cleaner generating resources. Thus, 
the data lag on the whole will inure to the compliance benefit of EGUs 
by resulting in dynamic budgets that are generally calculated at levels 
likely to be somewhat higher than what a dynamic budget calculation 
reflecting real-time EGU operations would produce. The EPA believes 
this data lag is worthwhile to provide more compliance planning 
certainty and advance notice to affected EGUs of the dynamic budget 
applicable to an upcoming control period. Furthermore, this data lag in 
dynamic budget computation is comparable to the data lag of quantifying 
preset state budgets for 2023 through 2025 based upon 2021 data, and at 
no point in the long history of EPA's trading programs has such a data 
lag in state budget computation yielded any compliance problems for 
affected EGUs. Without dynamic budgeting, the data lag inherent in 
calculating preset budgets would grow unabated with the passage of 
time, as a fixed reference year of heat input levels would continually 
apply regardless of potentially higher heat input levels farther and 
farther into the future. By eliminating the increase in the length of 
the data lag, this new dynamic budgeting approach is a substantial 
improvement in performance of the program relative to previous 
approaches that were not capable of capturing changes over time in the 
fleet and its utilization beyond the scheduled changes known to the EPA 
at the time of establishing preset budgets.
    The EPA disagrees that this lag will in fact pose compliance 
challenges for EGUs even if the unlikely scenario described by 
commenters were to occur. Several factors influence this. First, the 
change in methodology to preset budgets serving as a floor on budgets 
through 2029 means that the dynamic budget methodology can only produce 
an increase in the budget from this final rule through that year. 
Second, the adoption of a multi-year approach for identifying the heat 
input used to calculate the dynamic budgets will smooth the year-to-
year budget changes and effectively eliminate the possibility of 
greatest concern, which was that a single year of unusually low heat 
input would be used to set the budget for a subsequent year that turned 
out to have unusually high heat input. While a year of unusually high 
heat input for a given state may still occur, the state's budgets for 
those years will never be based on heat input from an anomalously low 
year, but instead will always be based on an average of several years' 
heat input. Third, because the Group 3 trading program is an interstate 
program implemented over a wide geographic region, and it is unlikely 
that all regions of the country would uniformly experience a marked 
increase in fossil fuel heat input necessitating an additional supply 
of allowances, it is likely that allowances will be available for trade 
from one area of the country where there is less demand to another area 
where there is greater demand. Fourth, as explained in section VI.B.5 
of this document, each state's assurance level will adjust to reflect 
actual heat input in that year. Specifically, the EPA will determine 
each state's variability limit for a given control period so that the 
percentage value used will 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. Thus, if in year 2030, for 
example, a state's actual heat input levels increase to a level that is 
not reflected in the dynamic budget calculation using earlier years of 
data, the assurance level (which absent the unusually high heat input 
would be 121 percent of the state's budget) will be calculated by the 
EPA following the 2030 ozone season, using that higher reported heat 
input. This will avoid imposing a three-for-one allowance surrender 
penalty on sources except where emissions exceed the assurance level 
even factoring in the increase in heat input in that year. Finally, as 
some commenters observed, the inherent data lag in dynamic budget 
quantification means that a state budget for the year 2030 will 
continue to reflect emissions from any EGU that retires before the 2030 
control period but is still operating anytime during the 2026-2028 
reference years from which the 2030 dynamic budget will be calculated. 
Given the likely ongoing trend of relatively high-emitting EGU 
retirements over time, this method for determining dynamic budgets 
should further assist the ability of remaining EGUs to obtain 
sufficient allowances to cover future heat input levels.
    With respect to the comments expressing concern that dynamic 
budgets would create too much slack because of the lag in incorporating 
retirements, the EPA observes that dynamic budgets will yield a closer 
representation of Step 3 control stringency across the future fleet 
than preset budgets for years in which retirement plans are currently 
relatively unknown. Moreover, any risk that the lag would lead to an 
unacceptably large surplus of allowances is limited by EPA's 
finalization of the annual bank recalibration to 21 percent and 10.5 
percent of the budget beginning in 2024 and 2030 respectively. The 
corresponding risk that a lag will lead sources to not operate 
emissions controls, due to a surplus of allowances, is also limited by 
the backstop daily emissions rates that start in 2024 (for sources with 
existing SCR controls) and no later than 2030 for other coal-fired 
sources.
    Comment: Commenters allege that the dynamic budget methodology is 
effectively a ``one-way ratchet'' because, if EGUs pursue compliance 
strategies

[[Page 36785]]

such as reduced utilization or generation shifting to comply with the 
rule rather than install or optimize pollution controls pursuant to the 
identified Step 3 emissions control strategies, the effect will be that 
the dynamic budget calculated in a future year will reflect that 
reduced heat input, but the applied emissions rate assumption will be 
the same. Thus, the approach according to commenters actually 
``punishes'' sources for achievement of emissions reductions 
commensurate with EPA's Step 3 determinations through alternative 
compliance means, by producing a smaller budget in later years (less 
heat input multiplied by the same emissions rate). If the source again 
reduces utilization or shifts generation to comply with this budget, 
then budgets in later years will again ratchet down, and so on.
    Response: First, the claims of dynamic budgeting being a one-way 
ratchet are incorrect. As pointed out at proposal, the dynamic budget 
process would allow for increased utilization to result in increased 
budgets. Moreover, this concern is entirely mooted for the period 2026 
through 2029 with the shift to preset budgets serving as a floor; 
dynamic budgeting can only increase the budget used in any given year 
in this time period. Additionally, the use of a multi-year average heat 
input in the budget-setting calculations will, on the whole, modulate 
the dynamic budgets such that the budgets over time will only gradually 
change with changes in the operating profile of the EGU fleet.
    For the control periods 2030 and later, this rule is premised on 
the expectation that all large coal-fired EGU sources identified for 
SCR-retrofit potential will, if they continue operating in 2030 or 
later, have installed the requisite post-combustion controls. Thus, the 
backstop daily emissions rate applies for all such sources beginning in 
the 2030 ozone season. In this latter period (post-2030), the EPA 
disagrees that the dynamic budget will punish fleet segments seeking to 
continue to pursue a strategy of reduced utilization. Rather, the 
dynamic budget will simply continue to reflect the Step 3 emissions 
control stringency. For instance, if there are two otherwise high-
emitting sources in a state that can reduce emissions by operating SCR, 
this rule's control stringency finds it cost effective for both sources 
to operate their controls. If one source retires and is replaced by new 
lower-emitting generation, it is not a punishment to have the budgets 
adjust in a way that still incentivize remaining units to operate their 
controls. This is simply right-sizing the budget to an evolving fleet. 
It is a feature of the rule, not a flaw, and is designed to address 
observed instances in prior rules where market-driven reduced 
utilization resulted in non-binding (i.e., overly slack) budgets and 
corresponding conditions where the incentive to operate a control 
dissipated over time. In the event that sources reduce utilization 
whether for compliance purposes or market-driven reasons, that also 
does not obviate the importance of continuing to incentivize the Step 3 
emissions control stringency at identified sources.
c. Final Preset State Emissions Budgets
    For affected EGUs in each covered state (and Indian country within 
the state's borders), this final rule establishes preset budgets for 
the control periods 2023 through 2029. For control periods 2026 through 
2029, any of those preset budgets may be supplanted by the 
corresponding dynamic budget that will be tabulated at later date, if 
and only if that dynamic budget yields a higher amount. For 2030 and 
beyond, the dynamic budget formula promulgated in this rule will be 
applied to future year data to quantify state emissions budgets for 
those control periods. The 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 VI.B.9 of 
this document. The amounts of the final preset state emissions budgets 
for the 2023 through 2029 control periods are shown in Table VI.B.4.c-
1.

    Table VI.B.4.c-1--CSAPR NOX Ozone Season Group 3 Preset State Emissions Budgets for the 2023 Through 2029
                                                 Control Periods
                                                 [Tons] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                 Final       Final       Final      Preset      Preset      Preset      Preset
                               emissions   emissions   emissions   emissions   emissions   emissions   emissions
            State               budgets     budgets     budgets     budgets     budgets     budgets     budgets
                               for 2023    for 2024    for 2025    for 2026    for 2027    for 2028    for 2029
----------------------------------------------------------------------------------------------------------------
Alabama.....................       6,379       6,489       6,489       6,339       6,236       6,236       5,105
Arkansas....................       8,927       8,927       8,927       6,365       4,031       4,031       3,582
Illinois....................       7,474       7,325       7,325       5,889       5,363       4,555       4,050
Indiana.....................      12,440      11,413      11,413       8,410       8,135       7,280       5,808
Kentucky....................      13,601      12,999      12,472      10,190       7,908       7,837       7,392
Louisiana...................       9,363       9,363       9,107       6,370       3,792       3,792       3,639
Maryland....................       1,206       1,206       1,206         842         842         842         842
Michigan....................      10,727      10,275      10,275       6,743       5,691       5,691       4,656
Minnesota...................       5,504       4,058       4,058       4,058       2,905       2,905       2,578
Mississippi.................       6,210       5,058       5,037       3,484       2,084       1,752       1,752
Missouri....................      12,598      11,116      11,116       9,248       7,329       7,329       7,329
Nevada......................       2,368       2,589       2,545       1,142       1,113       1,113         880
New Jersey..................         773         773         773         773         773         773         773
New York....................       3,912       3,912       3,912       3,650       3,388       3,388       3,388
Ohio........................       9,110       7,929       7,929       7,929       7,929       6,911       6,409
Oklahoma....................      10,271       9,384       9,376       6,631       3,917       3,917       3,917
Pennsylvania................       8,138       8,138       8,138       7,512       7,158       7,158       4,828
Texas.......................      40,134      40,134      38,542      31,123      23,009      21,623      20,635
Utah........................      15,755      15,917      15,917       6,258       2,593       2,593       2,593
Virginia....................       3,143       2,756       2,756       2,565       2,373       2,373       1,951
West Virginia...............      13,791      11,958      11,958      10,818       9,678       9,678       9,678
Wisconsin...................       6,295       6,295       5,988       4,990       3,416       3,416       3,416
                             -----------------------------------------------------------------------------------

[[Page 36786]]

 
    Total...................     208,119     198,014     195,259     151,329     119,663     115,193     105,201
----------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ The state emissions budget calculations pertaining to Table VI.B.4.c-1 are described in greater detail in
  the Ozone Transport Policy Analysis Final Rule TSD. Budget calculations and underlying data are also available
  in Appendix A of that TSD.
\b\ In the event this final rule becomes effective after May 1, 2023, the emissions budgets and assurance levels
  for the 2023 control period will be adjusted under the rule's transitional provisions to ensure that the
  increased stringency of the new budgets would apply only after the rule's effective date. The 2023 budget
  amounts shown in Table VI.B.4.c-1 do not reflect these possible adjustments. The transitional provisions are
  discussed in section VI.B.12 of this document.

5. Variability Limits and Assurance Levels
    Like each of the other CSAPR trading programs, the Group 3 trading 
program 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 
principle that each state's sources must be held to the elimination of 
significant contribution within that 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 
Group 3 trading program regulations in effect before this rulemaking 
was 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.\319\
---------------------------------------------------------------------------

    \319\ 531 F.3d at 908.
---------------------------------------------------------------------------

    In this rulemaking, the EPA did not propose and is not making 
changes to the basic structure of the Group 3 trading program's 
assurance provisions, which will 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 will continue to apply a 3-
for-1 surrender ratio to emissions exceeding the state's assurance 
level.\320\ Each assurance level also will continue to apply to the 
collective emissions of all units within the state and Indian country 
within the state's borders.\321\ However, the EPA is making a change to 
the methodology for determining the variability limits. Specifically, 
the EPA will determine each state's variability limit for a given 
control period 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 will 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 
historical 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 is 130 percent of the historical heat input used in 
computing the state's 2025 budget, then the state's variability limit 
for the 2025 control period will be 30 percent of the state's emissions 
budget instead of 21 percent of the state's emissions budget. The EPA 
expects that the minimum 21 percent will apply in almost all instances, 
and that the alternative, higher percentage value will apply only in 
control periods where operational variability causes an unusually large 
increase relative to the historical data used in setting the state's 
emissions budget, which would be a situation meriting a temporarily 
higher variability limit and assurance level. The revised methodology 
for determining the variability limits will apply both with respect to 
control periods when a state's emissions budget is a preset budget 
established in this final rule and with respect to control periods when 
a state's emissions budget is a dynamically-determined budget computed 
using the procedures laid out in the regulations, and it will apply 
starting with the 2023 control period rather than starting with the 
2025 control period as proposed.
---------------------------------------------------------------------------

    \320\ As discussed in section VI.B.8, the EPA is also 
establishing a new secondary emissions limitation for individual 
units that will apply in situations where an exceedance of the 
relevant state's assurance level has occurred.
    \321\ 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 revision to the variability limits is to better 
align the variability limits for successive control periods with the 
heat input data used in setting the state emissions budgets. Under the 
final rule, each dynamically

[[Page 36787]]

determined emissions budget will be computed using the latest available 
reported heat input, which for each budget set for a control period in 
2026 or a later year will be the average state-level heat input for the 
control periods two, three, and four years before the control period 
whose budget is being determined (for example, the dynamic state 
emissions budgets for the 2026 control period will be computed in early 
2025 using the reported state-level heat input for the 2022-2024 
control periods). The revised variability limits will 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 multi-year average heat input 
used in computing the state's emissions budget will 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 is thus entirely consistent with the 
overall purpose of including variability limits in the assurance 
provisions.
    As discussed in sections VI.B.1.b.i and VI.B.4, for the 2023-2025 
control periods the state emissions budget for a given control period 
will be the preset budget determined in this rule, and for the 2026-
2029 control periods, the state emissions budget for a given control 
period will be the preset budget determined in this rule rather than 
the dynamically determined budget computed in the year before the 
control period unless the dynamic budget is higher than the preset 
budget. If the state emissions budget is the preset budget, the 
historical heat input data reflected in that budget will be the heat 
input data for the 2021 control period, adjusted to reflect projected 
changes in fleet composition over time that are known at the time of 
this rulemaking, but not adjusted to reflect changes in fleet 
composition that are not known at the time of the rulemaking or changes 
in the utilization of individual units.\322\ In this case, the 
variability limit for the control period would be the higher of 21 
percent or the percentage change in the actual heat input for the 
control period relative to the heat input for the 2021 control period 
as adjusted to reflect the projected changes in fleet composition. The 
EPA believes it is reasonable to apply the same principle in setting 
the variability limit in control periods where the preset floor budgets 
are used as in control periods where the dynamically determined budgets 
are used, because the preset floor budgets are computed using the same 
principles as the dynamically determined budgets, with the major 
difference being that the available heat input data used in computing 
the preset budgets are necessarily less current. Accordingly, because 
preset budgets established in this manner are used starting with the 
2023 control period, the EPA believes it is also reasonable to begin 
implementing the revised methodology for determining variability limits 
starting with the 2023 control period.
---------------------------------------------------------------------------

    \322\ The total heat input amount used in computing each state's 
preset emissions budget for each control period from 2023 through 
2029 is included in Appendix A of the Ozone Transport Policy 
Analysis Final Rule TSD at column I of the ``State 2023''-``State 
2029'' worksheets.
---------------------------------------------------------------------------

    The reason the EPA is using the higher of a fixed 21 percent 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 revision will have the consequence 
that the state's final variability limit and assurance level for the 
control period also will not be known until after the control period. 
However, because the rule provides that the variability limit will 
always be at least 21 percent, the sources in a state will be able to 
rely for planning purposes on the knowledge that the assurance level 
will 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 fleet 
owner 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 the emissions from 
its fleet to exceed the fleet's aggregated share of the state's 
assurance level for the control period. Knowing that the variability 
limit will always be at least 21 percent will provide sources with 
minimum values they could use for such planning purposes.
    The EPA believes that 21 percent is a reasonable value to use as 
the minimum variability limit. 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 97.810, along with the 
respective state budgets.\323\ 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.\324\ 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 a higher percentage for the 
covered state with the smallest total heat input figures in this 
analysis--New Jersey--the EPA does not consider it appropriate to raise 
the minimum variability limit percentage beyond 21 percent for all 
other covered states based on the analytic results for one state, where 
small absolute heat input figures have resulted in a larger variability 
percentage.\325\ (Moreover, because of the provision allowing a state's 
variability limit for a given control period to be higher than 21 
percent if the state's actual heat input exceeds the heat input used to 
set the state's emissions budget by more than 21 percent, there is no 
need to set a minimum variability limit higher than 21 percent 
specifically for New Jersey.) Based on the consistent conclusions of 
these multiple analyses, the EPA is continuing to use 21 percent as the

[[Page 36788]]

minimum value in the revised approach for establishing variability 
limits for all control periods under this rule.
---------------------------------------------------------------------------

    \323\ Briefly, the 21 percent variability limit was determined 
in the analysis by identifying, for all the states in the region 
covered by the ozone season NOX trading program, and at a 
95 percent confidence level, the maximum expected deviation in any 
state's total heat input for any single control period in the data 
sample from that state's trend-adjusted mean total heat input for 
all the control periods in the data sample. 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), available in the docket for this rule.
    \324\ 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'', available in the docket for this 
rule.
    \325\ 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 provisions of the final rule relating to assurance levels and 
variability limits are unchanged from proposal, with the exception that 
the provision establishing a higher variability limit for a state in a 
given control period where the state's actual heat input exceeds the 
heat input used in computing the state emissions budget for that 
control period by more than 21 percent will be implemented starting 
with the 2023 control period instead of the 2025 control period.
    Comment: Some commenters supported the EPA's proposal to raise a 
state's variability limit above 21 percent for a given control period 
if the state's actual heat input for the control period was more than 
121 percent of the historical heat input used to set the state's budget 
for that control period. These commenters agreed with the EPA that 
making this adjustment is consistent with the assurance provisions' 
purpose of strongly incentivizing each state to achieve its required 
emissions reductions within the state while also accounting for year-
to-year variability in electric system operations.
    One commenter stated that the EPA should not finalize the proposed 
revision to the variability limit provisions, claiming that by allowing 
sources in some states to increase utilization and heat input so as to 
exceed the state's budget by more than 21 percent in a given year, the 
adjustment would then cause the state's subsequent dynamically 
determined budgets to be higher, allowing greater emissions over time.
    Response: The EPA disagrees with the comment advocating against 
finalization of the proposed change to the variability limit 
provisions. The Agency continues to view the proposed change as useful 
for accommodating instances where, because of electrical system 
operating needs, a state's actual total heat input in a control period 
exceeds the historical heat input used to set the state emissions 
budget for the control period, potentially causing increased emissions 
even when all EGUs in a state are achieving emissions rates consistent 
with the Step 3 emissions control stringency. Moreover, the EPA does 
not believe that the provision would lead to higher overall program-
wide budgets. No extra allowances would be created by the increase in a 
state's variability limit, so with or without the adjustment, any 
allowances to cover the emissions in excess of the state's budget would 
still need to be obtained through acquisition of allowances issued to 
sources in other states or the use of banked allowances. Thus, to the 
extent that the change in the variability limit provisions facilitates 
shifting of generation from some states to other states, increased heat 
input in the first set of states would generally be offset by decreased 
heat input in the second set of states, such that any increases in 
future dynamic budgets for the first set of states would be offset by 
decreases in future dynamic budgets for the second set of states. In 
addition, the final rule's use of multiple years of historical heat 
input data to compute the dynamically-determined state budgets will 
moderate the effect of any single year's heat input on the dynamically-
determined budgets for future control periods.
6. Annual Recalibration of Allowance Bank
    As discussed in section VI.B.1.b of this document, the EPA is 
making two revisions to the Group 3 trading program designed to better 
maintain the Step 3 emissions control stringency over time. The first 
proposed revision, discussed in section VI.B.4 of this document, is to 
adopt a dynamic budget-setting methodology that will allow state 
emissions budgets in future years to reflect more accurate information 
about the composition and utilization of the EGU fleet. The second, 
complementary, revision is to recalibrate the bank of unused allowances 
each control period to prevent allowance surpluses from accumulating 
and adversely impacting the ability of the trading program in future 
control periods to maintain the Step 3 emissions control stringency.
    As proposed and now finalized in this rule, the bank recalibration 
process will start 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 has been completed. The 
recalibration process for each control period will 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 date of 
the first recalibration August 1, 2024. The recalibrations take place 
on 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 will be known shortly after the end of that control period, 
sources and other market participants will 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. The EPA will make an estimate of the applicable calibration 
ratio for each control period publicly available no later than March 1 
of the year of the control period for which the bank will be 
recalibrated.
    Before undertaking a recalibration process each control period, the 
EPA will 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 exceeds the 
target bank amount. (For this purpose, no distinction will 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 will not carry out any recalibration for 
that control period. If the total amount of unused allowances does 
exceed the target bank amount, the EPA will determine for each account 
with holdings of banked Group 3 allowances the account-specific 
recalibrated amount of allowances, computed as the account's total 
holdings of banked Group 3 allowances immediately before the 
recalibration multiplied by the target bank amount and divided by the 
total amount of banked Group 3 allowances in all accounts, rounded up 
to the nearest allowance. Finally, the EPA will 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 will use an amount determined as a 
percentage of the sum of the state emissions budgets for the control 
period. For the control periods from 2024 through 2029, the target 
percentage will be 21 percent, which is the sum of the states' minimum 
variability limits.\326\ For control periods in 2030 and later years, 
the target percentage will be 10.5 percent, or half of the sum of the 
states' minimum

[[Page 36789]]

variability limits. In the proposal, the EPA cited two reasons for 
proposing the 10.5 percentage 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 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 percent confidence. This variability 
analysis is an application to the entire region of the variability 
analysis EPA has performed for individual states to establish the 
minimum variability limit of 21 percent for the states in the trading 
program.\327\ 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 reasonable 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.
---------------------------------------------------------------------------

    \326\ As discussed in section VI.B.5, an individual state's 
variability limit can be higher than 21 percent in a given control 
period if the state's actual heat input for that control period is 
more than 121 percent of the historical heat input used in computing 
the state emissions budget for the control period.
    \327\ 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.
---------------------------------------------------------------------------

    In the final rule, in response to comments, the EPA has determined 
to maintain the 10.5 target percentage for the reasons discussed in 
previous paragraphs, but to defer application of this target percentage 
until the 2030 control period. For the control periods from 2024 
through 2029, the EPA will instead use a target percentage of 21 
percent. The reason for using a higher target percentage for the 2024-
2029 control periods is to provide additional support for allowance 
market liquidity during these years, which both the EPA and commenters 
view as an important period of generating fleet transition for the 
power industry.
    The annual bank recalibrations, at either ratio, are an important 
enhancement to the trading program that will help maintain the control 
stringency determined to be necessary to address states' good neighbor 
obligations for the 2015 ozone NAAQS over time. Moreover, the 
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. As a consequence of this 
uncertainty, in some control periods, allowances banked from earlier 
control periods traded at lower prices than allowances issued for the 
current control period.\328\ The EPA considers the recalibration 
mechanism established in this rule to be simpler with less associated 
uncertainty. Following each bank recalibration, all allowances usable 
for compliance in the control period will have known, equal compliance 
values for the remainder of the control period and until the deadline 
for surrendering allowances after the control period.
---------------------------------------------------------------------------

    \328\ For more discussion of the progressive flow control 
mechanism, as well as allowance price data showing a discounted 
value for banked allowances, see ``NOX Budget Trading 
Program: 2005 Program Compliance and Environmental Results'' 
(September 2006) at 28-30, https://www.epa.gov/sites/default/files/2015-08/documents/2005-nbp-compliance-report.pdf.
---------------------------------------------------------------------------

    Finally, the EPA observes that the 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 is determining 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 
recalibration process will complement the revised budget-setting 
process by preventing 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. For 
further discussion of the reasons for bank recalibration, see section 
VI.B.1.b.ii of this document.
    The bank recalibration mechanism finalized in this rule is 
unchanged from the proposal except for the final rule's adoption of a 
target percentage of 21 percent rather than 10.5 percent for the 
control periods from 2024 through 2029. The EPA's responses to comments 
on the bank recalibration mechanism are discussed in the remainder or 
this section and in section 5 of the RTC document. Further discussion 
of the reasons for adopting a higher target percentage for the 2024-
2029 control periods is included in section VI.B.1.d of this document.
    Comment: Some commenters acknowledged the EPA's authority to manage 
the quantities of allowances carried over from one control period to 
the next as banked allowances, including some commenters who as a 
policy matter did not support such an approach. Other commenters 
claimed that any removal from the program of allowances banked in 
earlier control periods would constitute an unlawful taking of property 
or would constitute unlawful overcontrol.
    Response: The EPA disagrees with comments contending that the 
proposed bank recalibration provisions would be unlawful, either as 
asserted takings of property or as over-control for purposes of the 
Good Neighbor provision. With respect to the claim that removing 
allowances would constitute takings of property, the commenters 
misconstrue the nature of an allowance. The allowances used in the 
Group 3 trading program are created under the program's regulations, 
which expressly provide that the allowances are not property rights but 
are limited authorizations to emit NOX in accordance with 
the provisions of the Group 3 trading program.\329\ These provisions of 
the Group 3 trading program regulations have been in existence since 
the Revised CSAPR Update and were not reopened in this action. This 
approach of creating limited authorizations to engage in particular 
forms of conduct within a regulatory program extends back to the Acid 
Rain Program, where the approach was mandated by Congress, and has been 
followed by EPA in each subsequent allowance trading program for the 
electric power sector.\330\ Moreover, as noted earlier in this section, 
the Group 3 trading program regulations provide the EPA

[[Page 36790]]

Administrator with the 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, and the Administrator is making such a determination 
in this rule.
---------------------------------------------------------------------------

    \329\ 40 CFR 97.1006(c)(6)-(7).
    \330\ See, e.g., 42 U.S.C. 7651b(f) and 40 CFR 72.9(c)(6)-(7) 
(Acid Rain Program example); 40 CFR 97.6(c)(6)-(7) (Federal 
NOX Budget Trading Program example); 40 CFR 97.106(c)(5)-
(6) (CAIR NOX Annual Trading Program example).
---------------------------------------------------------------------------

    The EPA also disagrees that bank recalibration would constitute 
overcontrol. The emissions that are permissible in a given control 
period consistent with the Step 3 control stringency are quantified in 
the state emissions budgets for the control period. Banked allowances 
from previous control periods are necessarily surplus to the state 
emissions budgets for the current control period. As noted in section 
VI.B.1, in an allowance trading program, banking provisions can serve 
several useful purposes, including 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. 
However, these useful purposes do not include allowing sources to plan 
to emit in excess of the Step 3 control stringency as represented by 
the state emissions budgets for the control period. Accordingly, in the 
overcontrol analysis discussed in section V.D.4, the EPA analyzed 
whether the emissions reductions necessary to meet the state emissions 
budgets without relying for compliance purposes on any allowances 
banked in earlier control periods would result in overcontrol and 
determined there would be no overcontrol. (That is, the modeling of the 
effects of the Group 3 emissions budgets in 2026 did not include an 
assumption that there would be any banked allowances.) Thus, even if 
the Agency had finalized regulatory provisions removing all banked 
allowances from the trading program between control periods--in 
contrast to the actual bank recalibration provisions, which permit 
substantial quantities of banked allowances to remain in the trading 
program--the information available to the Agency suggests such 
provisions would not constitute over-control. With respect to some 
commenters' assertions that bank recalibration would over-control by 
``writing off'' emission reductions that may have gone beyond the 
reductions necessary to address the Good Neighbor provision or would 
make it more difficult to create surplus allowances in one control 
period to offset excess emissions in later control periods, EPA notes 
that the NAAQS apply continuously, and the possibility that the sources 
in a state may have done more than the minimum necessary to meet the 
state's Good Neighbor obligations in one control period does not create 
a right for the state to do less than is necessary to meet the state's 
Good Neighbor obligations in subsequent control periods.
    Comment: Some commenters expressed concern that excessive 
quantities of banked allowances, like excessive quantities of budgeted 
allowances, can lead to lower allowance prices. The commenters observed 
that with lower allowance prices, some units would likely operate their 
controls less effectively, resulting in a greater likelihood that the 
emissions stringency found necessary in this rule would not be 
sustained. Other commenters expressed the view that other provisions of 
the rule, including more stringent state emissions budgets, the 
backstop daily NOX emissions rate provisions, and the 
assurance provisions would be sufficient to incentivize EGUs to operate 
their controls effectively, making allowance bank recalibration 
superfluous for this purpose.
    Response: The EPA agrees with the comments explaining that without 
bank recalibration, the quantities of banked allowances can grow, 
leading to lower allowance prices, diminished incentives for sources to 
optimize control operation, and greater risk of failure to sustain the 
Step 3 control stringency, and disagrees with the comments arguing that 
other rule provisions would make bank recalibration unnecessary. The 
suggestion that the assurance provisions can maintain program 
stringency regardless of allowance quantities ignores the fact that the 
emission levels consistent with the Group 3 control stringency in a 
given control period are the state emissions budgets, not the higher 
assurance levels. If the quantities of banked allowances in the program 
grow to the point where sources collectively can plan to emit above the 
collective state emissions budgets, then the trading program would be 
unable to ensure that the Group 3 control stringency is being achieved, 
even if emissions do not rise further than the assurance levels. 
Further, there are now examples from the Group 2 trading program of 
sources emitting in excess of the state-wide assurance levels, because 
a glut of banked allowances which was not prevented by the regulations 
for that trading program rendered even the three-to-one surrender ratio 
ineffective. Suggestions that the backstop emissions rate provisions 
can maintain program stringency regardless of the quantities of banked 
allowances are similarly mistaken, because rather than reducing overall 
emissions of all sources in the trading program, the backstop rate 
provisions are designed to ensure that the largest individual sources 
of potential emissions operate their controls consistently. If the 
quantities of banked allowances are allowed to grow to the point where 
sources collectively can plan to emit above the collective state 
emissions budgets, the backstop rate provisions would do nothing to 
constrain emissions from the sources not subject to the backstop rate.
    With respect to the suggestion that state emissions budgets 
reflecting sufficient control stringency can avoid the need for bank 
recalibration, the EPA observes that the budget-setting and bank 
recalibration provisions in this rule are complements, not substitutes. 
If in a given year sources collectively emit against the collective 
state emissions budgets such that the ending allowance bank--that is, 
the allowances remaining after deduction of the allowances required for 
compliance--is less than the bank target amount, then the bank will not 
be recalibrated for the following control period. However, in the event 
that sources collectively emit against the collective state emissions 
budgets such that the ending allowance bank is above the bank target 
amount, then the recalibration provisions will ensure that the 
recalibrated allowance bank does not introduce an excessive overall 
quantity of allowances into the trading program for the following 
control period when combined with the state emissions budgets 
calculated for that control period. Without the recalibration 
provisions, the trading program would lack any mechanism for removing 
excess allowances that are inconsistent with maintaining the Step 3 
emissions control stringency which the Step 4 trading program is 
designed to implement.
    Comment: Some commenters claimed that the recalibration process 
itself would have undesirable consequences. First, some said that 
because bank recalibration would be executed partway through the 
control period, it would introduce uncertainty concerning the 
quantities of allowances each source would have available, impeding 
efforts to plan. Second, some commenters claimed that the prospect of 
bank recalibration would create counterproductive incentives for 
allowance holders. According to the commenters, allowances holders 
would be incentivized to ``use or lose'' their allowances (to reduce 
the number of allowances that would be removed from

[[Page 36791]]

their accounts in the recalibration process), thereby causing increased 
emissions, or alternatively would be incentivized to refuse to sell 
allowances (to allow the holders to have more allowances after the next 
recalibration), thereby reducing allowance market liquidity.
    Response: The EPA disagrees with these comments. As discussed 
previously in this section, the recalibration process has been 
scheduled for August 1 of each control period because compliance for 
the previous control period (and the associated allowance trading 
activities) would not be completed until after June 1. However, the 
information needed to project the degree of recalibration will be 
available by early November of the previous year, and the EPA will make 
an estimate publicly available no later than March 1, two months before 
the start of the control period. Further, at least 80 percent of the 
allowances for use in a given control period will be the allowances 
allocated from the state emissions budgets (with the recalibrated 
banked allowances from the prior control period comprising the 
remainder), and the emissions budgets and unit-level allocations 
amounts will be known approximately a year before the start of the 
control period.
    The comments claiming that the introduction of a bank recalibration 
process would create incentives to ``use or lose'' allowances or to 
hoard allowances are not persuasive. By reducing the supply of 
allowances carried over from previous control periods, bank 
recalibration would tend to raise the price of allowances in the 
current control period, making it more cost-effective and therefore in 
sources' interest to further reduce their emissions than to increase 
their emissions. Higher allowance prices would also increase the cost 
of hoarding allowances just as higher fuel prices raise the cost of 
maintaining large fuel inventories. Moreover, the EPA expects that the 
prospect of having banked allowances recalibrated after the end of the 
control period is much more likely to discourage hoarding than to 
encourage it. Given the choice between holding an allowance which may 
be removed as part of an upcoming recalibration process or instead 
selling the allowance for cash, the sale option will become more 
attractive. By creating a ``sell or lose'' incentive for holders of 
surplus allowances, the recalibration process should increase allowance 
market liquidity. At the same time, by ensuring a banked allowance will 
always have some value for use in a future control period, the bank 
recalibration mechanism in this program will continue to incentivize 
early emissions reductions.
    Comment: Turning to the level of the bank recalibration target, 
some commenters objected to the target bank percentage of 10.5 percent, 
saying that a larger bank would be needed to ensure that sufficient 
allowances would be available to enable sources to run as needed to 
provide reliable electricity service, particularly with the large year-
to-year swings in budgets that the commenters anticipated could occur 
with dynamic budgets computed using a single rolling historical year 
and with anticipated growth in renewable generation. Some commenters 
recommended a target bank percentage of 21 percent. Some commenters 
stated that even if the overall quantity of allowances available for 
use was greater than the total amount of emissions, a larger bank of 
allowances would facilitate trading and promote greater allowance 
market liquidity, citing reports of high allowance prices in 2022.
    Response: As discussed in sections VI.B.1.d and VI.B.4 and earlier 
in this section, the EPA does not agree with comments suggesting that 
annual bank recalibration in itself poses a risk to electric grid 
reliability. Nevertheless, the Agency has made several changes from 
proposal in the final rule designed to address concerns expressed about 
reliability by increasing compliance flexibility through the 2029 
control period. These changes through the 2029 control period include 
the use of a target bank percentage of 21 percent and the promulgation 
of preset budgets that will serve as the state emissions budgets unless 
the dynamic budgets for the control periods are higher. In addition, to 
reduce year-to-year variability under the budget-setting methodology, 
dynamic budgets will be calculated using multiple years of historical 
heat input data instead of heat input data from a single year. The EPA 
views these changes as responsive to the principal reasons that 
commenters gave for their claims that the target bank percentage should 
be higher than 10.5 percent. Regarding the claim that a higher target 
bank percentage is needed because increased renewable generation makes 
the demand for fossil generation more variable, commenters did not 
provide evidence demonstrating that the overall quantities of fossil 
generation throughout the multi-state region covered by this rule--as 
opposed to the operating patterns of some individual units--are 
becoming more variable, and the Agency declines to make an adjustment 
for such a reason at this time.
    With respect to the comments advocating for an even higher bank 
target percentage to facilitate trading and promote market liquidity, 
the Agency observes that any such advantage of larger allowance banks 
must be balanced with the disadvantages of excess allowance supply--
specifically, reduced allowance prices, diminished incentives for 
sources to optimize control operation, and greater risk of failure to 
sustain the Step 3 control stringency. In the final rule, the EPA finds 
that a reasonable balance between these opposing considerations is 
struck by temporarily adopting a higher bank target percentage of 21 
percent (consistent with the initial bank targets used in this rule and 
previous rules) and deferring implementation of the 10.5 percent target 
bank percentage identified by the Agency's analysis as a sustainable 
percentage in the longer term until the 2030 control period.
7. Unit-Specific Backstop Daily Emissions Rates
    While the identified EGU emissions reductions in section V of this 
document (i.e., the Step 3 emissions control stringency) 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 a backstop daily emissions rate of 0.14 lb/mmBtu 
applied to coal-fired steam units serving generators with nameplate 
capacity greater than or equal to 100 MW in covered states, except 
circulating fluidized bed units. This is important for ensuring the 
elimination of significant contribution on a more consistent basis from 
the relevant sources and over each day of the ozone season.
    Starting with the 2024 control period, a 3-for-1 allowance 
surrender ratio (instead of the usual 1-for-1 surrender ratio) will 
apply to emissions during the ozone season from any large coal-fired 
EGU with existing SCR controls exceeding by more than 50 tons a daily 
average NOX emissions rate of 0.14 lb/mmBtu. The daily 
average emissions rate provisions will apply to large coal-fired EGUs 
without existing SCR controls (except circulating fluidized bed units) 
starting with the second control period in which newly installed SCR 
controls are operational at the unit, but not later than the 2030 
control period. See Appendix A of the Ozone Transport Policy Analysis 
Final Rule

[[Page 36792]]

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 will apply.
    For each unit subject to the backstop daily emissions rate 
provisions for a given control period, the amount of emissions subject 
to the 3-for-1 surrender ratio will be determined as follows, generally 
on an automated basis using the unit's data acquisition and handling 
system (DAHS) required under 40 CFR part 75. For each day of the 
control period where the unit's average emissions rate for that day was 
higher than 0.14 lb/mmBtu, the owner or operator will compute what the 
unit's reported emissions on that day would have been (given the unit's 
reported heat input for the day) at an emissions rate of 0.14 lb/mmBtu. 
The difference between the unit's emissions for the day as actually 
reported and the emissions that would have been reported if the unit's 
emissions rate was 0.14 lb/mmBtu is the unit's daily exceedance. The 
amount of emissions subject to the 3-for-1 surrender ratio for the 
control period is the sum of the unit's daily exceedances for all days 
of the control period minus 50 tons (but not less than zero).\331\ All 
calculations will rely on the data monitored and reported for the unit 
in accordance with 40 CFR part 75.
---------------------------------------------------------------------------

    \331\ In the regulatory text at 40 CFR 97.1024 defining the 
total quantity of allowances that must be surrendered for a source's 
emissions in a control period, these amounts of emissions for all 
the units at the source are subject to a requirement to surrender 
two extra allowances per ton in addition to the usual 1-for-1 
allowance surrender requirement, yielding a total surrender ratio of 
3-for-1 for emissions over the 50-ton threshold.
---------------------------------------------------------------------------

    The EGU NOX Mitigation Strategies Final 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 stakeholders' focus on providing daily assurance of 
control operation, which is consistent with the 8-hour form of the 2015 
ozone NAAQS and the tendency for ozone levels to spike on a diurnal 
cycle, the 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.\332\ 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. This 
seasonal rate reflects the average across a unit's range of varying 
daily rates reflecting different operation conditions. 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.
---------------------------------------------------------------------------

    \332\ 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.\333\ 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 equivalent to a 30-day rate of 0.08 lb/mmBtu for purposes of this 
comparison of rates across averaging times) to a comparably stringent 
short-term limit (a daily rate of 0.14 lb/mmBtu).
---------------------------------------------------------------------------

    \333\ 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.
---------------------------------------------------------------------------

    The inclusion of a 50-ton threshold for emissions exceeding the 
backstop daily emissions rate before the 3-for-1 surrender applies is a 
change from the proposal. As discussed in section VI.B.1.d of this 
document, the EPA made this change in response to comments concerning 
the possibility that the 3-for-1 surrender ratio could otherwise have 
applied to emissions outside an EGU operator's control, with the most 
important example being the emissions during unit startup before SCR 
equipment can be brought into service, and to a lesser extent the 
emissions during unit shutdown. The analysis used by the EPA to derive 
the 50-ton threshold is described in detail in the Ozone Transport 
Policy Analysis Final Rule TSD. Briefly, for a set of 164 SCR-equipped 
units with seasonal average NOX emissions rates at or below 
0.08 lb/mmBtu in 2021, the EPA evaluated the total amounts of emissions 
that would have been determined to exceed a daily average emissions 
rate of 0.14 lb/mmBtu in the 2021 and 2022 ozone seasons. In the 2021 
ozone season, only 572 tons out of these units' total emissions of 
60,350 tons, or 0.9 percent, would have been considered exceedances, 
with an average exceedance per unit of less than 4 tons. The highest 
amount for any of the 164 individual units in either ozone season was 
48 tons. Based on this analysis, the EPA concludes that adding a 50-ton 
threshold to the backstop daily emissions rate provisions will ensure 
that substantially all emissions outside the control of an SCR-equipped 
unit's operator will not be subject to the 3-for-1 surrender ratio. 
Because there is no reason to expect the range of emissions during 
conditions when SCR controls cannot be operated to differ between SCR-
equipped units and units without SCR, inclusion of the 50-ton threshold 
effectively prevents application of the 3-for-1 ratio to emissions 
during startup and shutdown by units without SCR as well.
    At the same time, the EPA believes the 50-ton threshold is not 
large enough to eliminate the intended incentive to achieve emissions 
rates consistent with good SCR performance under conditions other than 
startup and shutdown. For a set of 124 SCR-equipped units with seasonal 
average NOX emissions rates above 0.08 lb/mmBtu, the total 
amount of emissions exceeding a daily average emissions rate of 0.14 
lb/mmBtu in the 2021 ozone season was 18,629 tons. Of this total 
amount, 15,374 tons would have been in excess of the 50-ton thresholds 
for the various units, indicating that even after application of the 
threshold, the 3-for-1 surrender ratio would have applied to over 80 
percent of the daily exceedance amounts.
    The backstop daily NOX emissions rate provisions 
finalized in this rule are unchanged from the proposal except for the 
inclusion of a 50-ton threshold for emissions exceeding the backstop 
emissions rate before the 3-for-1 surrender ratio applies and the 
deferral of the application of the provisions to units without existing 
SCR controls

[[Page 36793]]

until the 2030 control period or, if earlier, the second control period 
in which new SCR controls are operated at a unit. The EPA's responses 
to comments on the backstop daily NOX emissions rate 
provisions, including the reasons for these changes, are discussed in 
the remainder of this section and in section 5 of the RTC document.
    Comment: Some commenters strongly supported the backstop daily 
emissions rate provisions, noting their benefit to downwind receptors 
on potential nonattainment days, their benefit to neighboring 
communities, and evidence of deterioration in SCR performance in the 
absence of such provisions. Other commenters stated that the backstop 
daily emissions rate provisions are unnecessary, either because SCR-
equipped EGUs would already be sufficiently incentivized to operate and 
optimize their controls by the stringency of the state emissions 
budgets and the resulting allowance prices or because most SCR-equipped 
EGUs are already required to operate and optimize their SCRs by 
conditions in their operating permits. Some commenters cited previous 
EPA analyses showing that it is unusual for SCR-equipped units to turn 
off their SCRs only on high electricity demand days (HEDD).
    Commenters suggested diverse possible changes to the types of EGUs 
that would be covered by the backstop daily emissions rate provisions. 
Some commenters stated that the provisions should apply to all EGUs or 
to all SCR-equipped EGUs, including non-coal-fired units. Other 
commenters stated that exemptions should be provided for units 
operating at capacity factors below 10 percent or for emissions during 
emergencies.
    Some commenters stated that implementation of the backstop daily 
emissions rate provisions would cause unintended and counterproductive 
consequences. Some of these commenters claimed that by requiring the 
surrender of extra allowances, the backstop emissions rate provisions 
would create shortages of allowances for the program overall. Other 
commenters claimed that the disincentives to operate units subject to 
the backstop emissions rate provisions would cause load to shift to 
higher-emitting generators not covered by the trading program (such as 
sources in states outside the program's geographic region, EGUs smaller 
than 25 MW, and sources considered demand-side resources, including 
end-user-sited diesel generator units), potentially resulting in higher 
overall emissions.
    Response: The EPA agrees that backstop daily emissions rate 
provisions should be implemented and disagrees with comments suggesting 
that the need for the backstop daily emissions rate provisions is 
contradicted by previous EPA analyses or is already adequately 
addressed by other provisions of this rule or other legal requirements. 
As discussed in sections V.D.1 and VI.B.1.c of this document, the EPA 
has determined that a control stringency reflecting universal 
installation and operation of SCR technology at large coal-fired EGUs 
is appropriate. There are several important differences between this 
rule and previous actions addressing interstate ozone transport where 
the Agency did not include such provisions. First, this rule 
constitutes a full remedy, unlike some prior actions. Second, this rule 
is the first rule in which the EPA is addressing good neighbor 
obligations with respect to the more protective 2015 ozone NAAQS. 
Third, the EPA has examined the most recent data over a broader 
geographic and temporal footprint specific to the coverage of this 
rule, and it illustrates a greater degree of SCR performance erosion 
than in the prior years in which EPA conducted such analysis. Fourth, 
nonattainment and maintenance for this NAAQS are projected to persist 
well into the future in EPA's baseline, making enhancements and 
safeguards such as the backstop daily emissions rate provisions 
essential for securing elimination of significant contribution in 
future periods for which fleet configuration is inherently more 
uncertain.
    With respect to claims that inclusion of the backstop daily 
emissions rate provisions is contradicted by the EPA's earlier analyses 
concerning SCR operational changes specific to high electricity demand 
days, the EPA disagrees. Historical data reported to the EPA show that 
multiple SCR-equipped units across the states covered by this action 
have chosen not to operate their SCRs, or to operate them at materially 
less than their full removal capability, for entire ozone seasons. The 
apparent infrequency of one type of behavior--i.e., instances of units 
running their controls on most days but turning the controls off 
specifically on high electricity demand days--does not contradict the 
evidence concerning another type of behavior--i.e., non-operation or 
suboptimal operation of controls for entire ozone seasons. The evidence 
from previous trading programs demonstrates that reliance solely on the 
incentives created by allowance prices and corresponding static state 
emissions budgets has been insufficient to cause all SCR-equipped units 
to operate and optimize their controls for entire ozone seasons.
    The EPA acknowledges that some SCR-equipped units are likely 
already subject to other legal requirements calling for their SCR 
controls to be operated and optimized such that their seasonal average 
NOX emissions rates will generally not exceed 0.08 lb/mmBtu 
(the level of seasonal SCR performance that the EPA used to derive the 
equivalent 0.14 lb/mmBtu level of daily SCR performance for the 
backstop daily NOX emissions rate). However, commenters do 
not claim, and the EPA does not believe, that all SCR-equipped units 
are subject to other legal requirements calling for an equivalent 
degree of SCR operation and optimization. In the context of a multi-
state trading program, it is more efficient and equitable, and far more 
transparent, for the EPA to establish rule provisions uniformly 
incentivizing all large coal-fired EGUs to install and operate SCR 
controls than to attempt to establish differentiated requirements for 
various units according to the EPA's analysis of the effectiveness of 
their pre-existing permit conditions. Further, to the extent that a 
given unit's permits already require SCR performance that would meet 
the backstop emissions rate established in this rule, or to the extent 
that allowance prices would incentivize the unit to operate the SCR 
anyway, the EPA expects that the backstop daily emissions rate 
provisions (as finalized with a 50-ton threshold to address emissions 
outside an EGU's control before the 3-for-1 surrender ratio applies) 
will cause no incremental cost for the unit.
    The EPA disagrees with the suggested changes to applicability of 
the backstop emissions rate provisions. With respect to the comments 
advocating broader coverage, the EPA discusses its reasons for applying 
the provisions only to coal-fired EGUs in section VI.B.1.c of this 
document, including the fact that operation of SCR controls is a well-
established practice among the best performing coal-fired boilers but 
not for non-coal-fired units.\334\ The comments indicate a preference 
for a less flexible trading program design than the EPA has found 
appropriate but do not demonstrate that EPA's decision to allow greater 
flexibility is either impermissible or unreasonable; our reasoning in 
this regard is further explained in section VI.B.1.c.i of this

[[Page 36794]]

document. With respect to the comments advocating narrower coverage, 
the commenters have provided no information indicating that the sources 
for which exemptions are sought could not comply with the provisions, 
including through the surrender of additional allowances if necessary. 
The EPA notes that emissions from coal-fired units operating at low 
capacity factors may be concentrated around days of high electricity 
demand when incentives to minimize such emissions may be most helpful 
in mitigating downwind air quality problems. The EPA also notes that to 
the extent the comments are intended to support exemptions for units 
without existing SCR controls, the final rule defers application of the 
backstop emissions rate provisions to such units until the 2030 control 
period, providing additional flexibility to develop alternatives to the 
use of such units if the owners choose not to equip them with SCR 
controls.
---------------------------------------------------------------------------

    \334\ Nationwide and among operating units in 2021, EPA 
identified the best performing quartile (i.e., lowest ozone season 
emissions rate) of coal-fired EGU boilers (excluding CFB units). 
Nearly 100 percent of these units (159 of 160 units) were equipped 
with SCR controls.
---------------------------------------------------------------------------

    Finally, the EPA also disagrees with the comments asserting that 
the backstop emissions rate provisions would cause unintended and 
counterproductive consequences. With respect to units already equipped 
with SCR controls, the EPA expects that by far the most important 
effect of the provisions will be to incentivize the units to operate 
and optimize their controls. The EPA sees no basis for speculation that 
such units would choose to operate in a manner that would result in 
large amounts of emissions becoming subject to the 3-for-1 allowance 
surrender ratio or in generation being shifted to sources outside the 
trading program. The results of the EPA's modeling of benefits and 
costs of the rule show little leakage of emissions to non-covered 
sources, and commenters have presented no analysis to the contrary. For 
instance, as shown in Table 4.6 of the RIA, non-covered state ozone 
season NOX emissions increased on average by 1 percent over 
the 2023-2030 time period between the base and final rule scenarios, 
while covered state emissions fell by 14 percent on average over the 
same period. With respect to units without existing SCR controls, the 
EPA expects the backstop emissions rate provisions, when they would 
take effect for such units, to provide a strong incentive against 
extensive operation (unless and until such controls are installed), 
again not resulting in large amounts of emissions becoming subject to 
the 3-for-1 allowance surrender ratio.
    Comment: For units with existing SCR controls, the aspect of the 
backstop daily emissions rate provisions that received the most 
attention in comments was how emissions outside the operator's control 
should be treated. Multiple commenters expressed concern that the 
backstop daily emissions rate would be exceeded on days when the SCR 
equipment cannot be operated for all or a portion of the day. The most 
commonly cited example of a situation where SCR equipment cannot be 
operated was unit startups, although some commenters also mentioned 
unit shutdowns, boiler or emissions control malfunctions, and unit 
maintenance or tests. The commenters expressed the view that emissions 
that cannot be controlled by SCR equipment should be exempted from the 
backstop emissions rate provisions and suggested a variety of 
approaches for implementing an exemption.
    Some commenters also stated that the backstop emissions rate 
provisions would not sufficiently accommodate sustained low-load 
operation, such as where an SCR-equipped unit operates for extended 
periods at a load level too low to permit SCR operation so that the 
unit is ready to ramp up to higher load levels in less time than would 
be required for a startup. The commenters suggested that implementation 
of a backstop daily rate would reduce the ability to operate the units 
in this manner, generally reducing system flexibility. Some noted that 
the need for flexibility of this nature is increasing because of the 
rapid growth in intermittent renewable generation.
    Additional comments on the backstop daily emissions rate provisions 
for units with existing SCR controls addressed the level of the daily 
emissions rate and the implementation timing. With respect to the rate 
level, various commenters suggested rates from 0.08 to 0.20 lb/mmBtu. 
With respect to implementation timing, some commenters stated that 
because immediate compliance was possible, the good neighbor provision 
required implementation as of the 2023 control period rather than the 
2024 control period as proposed. Other commenters expressed the view 
that units with existing SCR controls should not be required to comply 
with the backstop emissions rate provisions earlier than units without 
existing SCR controls. Some owners of SCR-equipped EGUs that exhaust to 
stacks shared with EGUs without SCR suggested that their particular 
units with existing SCR controls should not be required to comply with 
the backstop emissions rate provisions earlier than units without 
existing SCR controls in order to avoid the cost of upgrading their 
emissions monitoring equipment.
    Response: With respect to the topic of emissions outside an 
operator's control, as a general matter the EPA agrees that the 
backstop daily emissions rate provisions are intended to incentivize 
good SCR operation and that it was not the Agency's intent to apply a 
higher surrender ratio to emissions that are truly unavoidable, such as 
emissions occurring before an operator could reasonably initialize SCR 
operation when a unit is started up. As explained elsewhere in this 
section, the EPA selected the level of the backstop rate based on 
analysis of 2021 emissions data showing that for SCR-equipped coal-
fired units achieving seasonal average NOX emissions rates 
at or below 0.08 lb/mmBtu, more than 99 percent of the units' emissions 
would fall below a backstop daily emissions rate of 0.14 lb/mmBtu. In 
response to the comments summarized previously, the EPA has further 
analyzed 2021 and 2022 emissions data to determine what if any 
modifications to the proposal might be appropriate to limit the 
imposition of a 3-to-1 allowance surrender requirement for emissions 
caused by circumstances outside an operator's control while preserving 
the intended incentive to operate and optimize SCR controls whenever 
possible. The analysis showed that for the same set of units achieving 
seasonal average emissions rates at or below 0.08 lb/mmBtu, the highest 
total amount of emissions exceeding the backstop daily emissions rate 
in either the 2021 or 2022 control period for any unit was 48 tons. The 
Agency views this amount as a reasonable upper bound on the quantity of 
emissions that might contribute to an exceedance of the backstop 
emissions rate arising from circumstances outside an operator's control 
for any coal-fired unit, not just the well-controlled units in the data 
set analyzed, because the amount generally encompasses all of a unit's 
emissions occurring in hours when an SCR could not be operated over an 
ozone season.
    Based on this analysis, the backstop daily emissions rate 
provisions in this final rule exclude the first 50 tons of a unit's 
emissions in a given control period exceeding the backstop daily 
emissions rate from incremental allowance surrender requirements. The 
EPA finds that establishing a threshold of this nature will provide an 
appropriate maximum exclusion to all coal-fired units for unavoidable 
emissions caused by circumstances outside the operator's control while 
maintaining the incentives for less well-controlled units to improve 
their emissions performance on all days of

[[Page 36795]]

the ozone season. Well-controlled units will likely have no emissions 
over the threshold that will be subject to incremental allowance 
surrender requirements, while for SCR-equipped units not already 
achieving a seasonal average emissions rates sufficiently low to 
routinely operate at daily average emissions rates of 0.14 lb/mmBtu or 
less, the incentive to reduce daily emissions rates will remain in 
place, because the 50-ton threshold is not expected to encompass all 
emissions exceeding the backstop daily emissions rate for such units. 
In contrast to more complicated exceptions suggested by commenters, the 
50-ton threshold can be easily integrated into the overall trading 
program structure with minimal additional recordkeeping and reporting 
requirements.
    With respect to the comments claiming that the inability of some 
SCR-equipped units to operate their SCR controls at sustained low load 
levels likewise merits alteration of the backstop daily emissions rate 
provisions, the EPA disagrees. There is no dispute concerning the 
technical need for a unit to attain and maintain a certain range of 
exhaust gas temperatures at the SCR inlet in order to achieve optimal 
SCR performance and no dispute concerning the general relationship 
between a unit's load level in a given hour and its ability to attain 
and maintain that exhaust gas temperature range in that hour. However, 
the EPA is also aware that at least in some cases, units whose role in 
the integrated electric system currently calls for them to operate at 
low load levels for sustained periods (such as overnight) in fact may 
be able to operate at slightly higher load levels that would 
accommodate SCR operation during those periods and still meet the needs 
of the integrated electric system, thereby avoiding operation of the 
unit for sustained periods with the SCR out of service. Figure B.5 in 
the EGU NOX Mitigation Strategies Final Rule TSD illustrates 
this opportunity using data reported for the 2021 and 2022 ozone 
seasons by a large SCR-equipped EGU in Pennsylvania. In both ozone 
seasons, the unit often cycled daily between its maximum load of 
approximately 900 MW during the daytime and a lower load level 
overnight, and in both ozone seasons the unit's typical daytime 
emissions rate was between 0.05 and 0.07 lb/mmBtu. However, while in 
the 2021 ozone season, the unit cycled down to a load level of 
approximately 440 MW overnight and did not operate its SCR, in the 2022 
ozone season, when allowance prices were considerably higher, the unit 
cycled down to a load level of approximately 540 MW overnight and did 
operate its SCR. Despite the higher nighttime generation levels, the 
result was a decrease of roughly 50 percent in the unit's seasonal 
average NOX emissions rate, from approximately 0.14 lb/mmBtu 
to approximately 0.07 lb/mmBtu, and a comparable reduction in 
NOX mass emissions. This unit is not uniquely situated; 
operating data for several other large SCR-equipped EGUs in 
Pennsylvania show the same past pattern of cycling down to low load 
levels at which the SCR controls cannot be operated, and these other 
units have similar opportunities to cycle down to somewhat higher load 
levels (necessarily subject to the needs and constraints of the 
integrated electric system) at which their SCR controls can be 
operated.\335\ No commenter has submitted data to the contrary. 
Furthermore, this example demonstrates the need for this rule's 
backstop emissions rate provision, which (had it been in place) would 
have motivated this facility to operate its SCR overnight during the 
2021 ozone season when the prevailing allowance price provided an 
insufficient incentive to do so.
---------------------------------------------------------------------------

    \335\ See the spreadsheet ``Conemaugh and Keystone unit 2021 to 
2022 hourly ozone season data'' in the docket.
---------------------------------------------------------------------------

    The EPA disagrees with the comments advocating for a backstop daily 
emissions rate lower or higher than 0.14 lb/mmBtu. In general, these 
comments simply represent disagreements with the EPA's conclusions 
regarding the identification of required emissions reductions under 
this rule, as reflected in part by the EPA's conclusion that a seasonal 
average emissions rate of 0.08 lb/mmBtu reasonably reflects the 
seasonal average emissions rate achievable through optimization of 
controls by existing SCR-equipped units that are not already achieving 
a lower seasonal average emissions rate. Comments concerning the 
selection of the 0.08 lb/mmBtu seasonal average emissions rate are 
addressed in section V of this document. Commenters did not challenge 
the EPA's analysis identifying a daily emissions rate of 0.14 lb/mmBtu 
as comparable in stringency to a seasonal average emissions rate of 
0.08 lb/mmBtu (see further discussion elsewhere in this section).
    The EPA also disagrees with the comments stating that the backstop 
daily emissions rate provisions should apply to units with existing SCR 
controls starting in a control period earlier or later than the 2024 
control period. The EPA does not consider implementation of the 
provisions in the 2023 control period feasible because it is currently 
unknown whether the necessary updates to the emissions recordkeeping 
and reporting software for all the affected sources could be completed 
and tested before July 30, 2023, which is the first quarterly reporting 
deadline for the 2023 control period. Moreover, as discussed in section 
VI.B.1.c.i of this document, implementing the requirements starting in 
2024 will provide a window for EGUs to improve the consistency of SCR 
operation or in some cases to optionally install additional emissions 
monitoring equipment. As for the suggestion that implementation timing 
of the backstop daily emissions rate provisions for units with existing 
SCR controls should be synchronized with the later implementation 
timing for units without existing SCR controls, the EPA is not 
persuaded that there is any inequity in implementing provisions 
intended to incentivize operation of SCR controls first at sources that 
already have such controls and later at sources that do not already 
have such controls, allowing time for the latter sources to install the 
controls. In any event, in this instance, where some upwind sources 
have an immediate and highly cost-effective option for controlling 
their emissions, the statutory requirement for significant contribution 
to be eliminated as expeditiously as practicable so as to provide 
downwind states with the protection intended by the Good Neighbor 
provision overrides these sources' claim of inequity relative to 
sources whose emissions control options would take longer and have 
higher cost. We conclude that the backstop daily emissions rate is an 
important aspect of the elimination of significant contribution and 
should be applied at the relevant units. It is only out of recognition 
of unique circumstances associated with facilitating power-sector 
transition as identified by commenters, that we defer the application 
of the rate for the minority of units that have not yet installed SCR 
controls.
    Finally, with respect to the SCR-equipped units that share common 
stacks with units that do not have SCR, the EPA disagrees that 
monitoring cost considerations merit a later implementation date for 
the backstop daily emissions rate provisions. As discussed in section 
VI.B.10 of this document, five plants with this configuration are 
covered by the rule (one of which has announced plans to retire in 
2023). Under this rule, as proposed, the owner of a plant with this

[[Page 36796]]

configuration can choose between either upgrading the plant's 
monitoring systems so as to obtain unit-specific NOX 
emissions rate data for each unit subject to the backstop daily 
emissions rate or else using the NOX emissions rate data 
from the common stack, recognizing that the common stack emissions rate 
would generally be biased upwards relative to the emissions rate that 
could be reported for the SCR-equipped unit if that unit's emissions 
were monitored separately. Commenters have suggested a third option of 
a temporary exemption from the backstop emissions rate to avoid the 
cost of upgrading their monitoring systems. With the timing for 
implementation of the backstop emissions rate provisions for currently 
uncontrolled units in the proposal, the temporary exemption for the 
SCR-equipped units would have been in place for three control periods, 
from 2024 through 2026. With the final rule's deferral of the 
implementation of the backstop emissions rate provisions for the 
uncontrolled units for up to three years, the suggested temporary 
exemption for the SCR-equipped units would be in effect for up to six 
control periods, from 2024 through 2029. The EPA does not consider it 
reasonable to allow these SCR-equipped units an exemption from the 
backstop rate provisions for six years to avoid the cost of upgrading 
their monitoring systems, particularly given that the additional costs 
of monitoring at the individual-unit level are already borne by the 
large majority of other plants and the rule already provides these 
plants with an alternative to the monitoring system upgrades, if 
desired, by allowing the plants to use the emissions rate data from the 
common stack.\336\
---------------------------------------------------------------------------

    \336\ The owner of one of the five plants with common stacks 
submitted comments stating that no location in the plant's ductwork 
could meet the criteria for a unit-specific monitoring location. As 
discussed in section VI.B.10 of this document, EPA staff have 
reviewed the comment and do not believe the commenter has provided 
sufficient information to reach such a conclusion.
---------------------------------------------------------------------------

    Comment: With respect to units without existing SCRs, some 
commenters viewed the backstop daily emissions rate provisions as 
likely to make units without SCR altogether unwilling or unable to 
operate and characterized the provisions as a mandate for such units to 
install such controls or retire as of the control period when the 
provisions are implemented. Other commenters acknowledged that the 
provisions are not actually hard limits but stated that the higher 
allowance surrender ratio for emissions in excess of the backstop daily 
rate would nevertheless reduce the ability of such units to operate as 
needed to back up intermittent renewable generation. Some commenters 
claimed that inclusion of the backstop daily emissions rate provisions 
would substantially eliminate the potential benefits of allowance 
trading, because all units would have to meet the same emissions rate.
    Some commenters stated that the proposed application of the daily 
backstop emissions rate provisions in the 2027 control period in some 
cases would occur only slightly before the units' otherwise planned 
retirement dates, and that short-term reliability considerations could 
create the need to make substantial investments in new controls at the 
units, which in turn could result in deferral of the units' retirement 
plans. In the proposal, the EPA requested comment on the possibility of 
deferring the application of the backstop emissions rate provisions to 
units without existing SCR controls until the 2029 control period if 
the owners provided the EPA with information indicating with sufficient 
certainty that the units would retire by the end of 2028. Commenters in 
favor of this concept suggested longer deferral periods, ranging from 
2029 through 2032, and some also suggested that the EPA should 
simultaneously enlarge the emissions budgets to provide more allowances 
for units subject to the deferred requirement. Other commenters opposed 
any deferral of the applicability of the backstop rate provisions.
    Response: The EPA disagrees that implementation of the backstop 
daily emissions rate provisions for EGUs without existing SCR controls 
constitutes a mandate for such units to install controls or retire but 
agrees that, as intended, the provisions would create strong incentives 
to minimize operation of the units unless and until controls are 
installed, and further agrees that in some instances retirement and 
replacement may be a more economically attractive option for the unit's 
customers and/or owners than installation of new controls. The EPA's 
rationale for determining at Step 3 that the control stringency 
required to address states' good neighbor obligations includes 
achievement of emissions rates consistent with good SCR performance at 
all large coal-fired EGUs (other than circulating fluidized bed 
boilers) is discussed in section V.D.1 of this document, and the EPA's 
rationale for determining at Step 4 that the trading program should 
include strong unit-level incentives to implement these controls is 
discussed in section VI.B.1.c. of this document. As noted in section 
VI.B.1.c of this document, the backstop daily emissions rate provisions 
are structured as incremental allowance surrender requirements rather 
than as directly enforceable emissions limits 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. The EPA 
appreciates that, in comparison to previous transport rules using a 
trading program mechanism for the power sector, the degree of 
flexibility available under this rule is reduced both by the greater 
stringency of the overall emissions reduction requirements, which leave 
less room to accommodate emissions from high-emitting units such as 
uncontrolled coal-fired units, and by the backstop daily emissions rate 
provisions. However, the EPA maintains that the trading program 
structure still is significantly more flexible than an array of 
directly enforceable emissions limits imposed on all EGUs or even on 
all coal-fired EGUs, and the comments do not show otherwise.
    With respect to the comments concerning the timing for application 
of the backstop daily emissions rate provisions to EGUs without 
existing SCR controls, in the final rule the provisions will apply to 
these units starting with the second control period in which newly 
installed SCR controls are operational at the unit, but not later than 
the 2030 control period. As discussed in section VI.B.1.d of this 
document, the purpose of this change from the proposal is to address 
concerns expressed by RTOs and other commenters that application of the 
backstop daily NOX emissions rate to EGUs without existing 
SCR controls starting in the 2027 control period would provide 
insufficient time for planning and investments needed to facilitate the 
unit retirements they viewed as likely to be a preferred compliance 
pathway for some owners. The EPA recognizes that retrofitting new 
emissions controls on aging coal-fired EGUs may be less environmentally 
efficient than the alternative of retirement and replacement, which 
could yield lower cumulative emissions of NOX and multiple 
other pollutants over time. The EPA also recognizes that several coal-
fired EGUs have already been considering retirement in 2028 (or 
earlier) under compliance pathways available under the Clean Water Act 
effluent guidelines \337\ and the coal combustion residuals rule under 
the

[[Page 36797]]

Resource Conservation and Recovery Act.\338\ The year 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.\339\ In addition, other regulatory actions at the state 
or Federal level are being or recently have been proposed. This 
includes among other things a proposed revision to the PM NAAQS for 
which transport SIPs would be due later in the 2020s. We understand 
that EGUs may wish to take the entire regulatory and market landscape 
into account when deciding whether to invest in SCR or pursue other 
NOX reduction strategies. To facilitate a unit-level 
compliance alternative under this rule that maintains the 
NOX reductions corresponding to SCR-level emissions control 
performance required by the state budgets from 2026 forward and that is 
potentially superior both economically and environmentally across 
multiple regulatory programs than installation of new, capital-
intensive, post-combustion controls, the EPA is providing the fleet 
more flexibility in how to achieve those emissions reductions in the 
years through 2029. Relatedly, the deferral of the application of the 
backstop emissions rate provisions to uncontrolled units also addresses 
commenters' concerns that the provisions otherwise would reduce the 
ability of uncontrolled units to operate as needed to back up 
intermittent renewable generation (subject of course to the allowance-
holding requirements to cover emissions). The deferral addresses this 
concern directly for the period through 2029, by eliminating 
application of the backstop provisions to uncontrolled EGUs through 
this period, and also indirectly after 2029, by ensuring the 
availability of sufficient time for owners and operators to complete 
other investments that may be needed to back up renewable generation 
after that point.
---------------------------------------------------------------------------

    \337\ See 40 CFR 423.11(w).
    \338\ See 40 CFR 257.103(b).
    \339\ See 40 CFR 51.308(f).
---------------------------------------------------------------------------

    The EPA disagrees with the comments stating that application of the 
backstop daily emissions rate provisions to uncontrolled units should 
not be deferred and also disagrees with the comments stating that 
deferral should be accompanied by increases in the state emissions 
budgets reflecting higher assumed emissions rates for these units. The 
responses to these two comments are related. This rule complies with 
the mandate for the EPA to address good neighbor obligations as 
expeditiously as practicable and is based on a demonstration that 
emissions reductions commensurate with the overall emissions control 
strategy at Step 3 can be achieved beginning in the 2027 ozone season 
(following a two-year phase in of emissions reductions associated with 
installation of SCR retrofits). In the RIA, we demonstrate that EGUs 
will have multiple pathways to meeting the state budgets even if they 
choose not to install the SCR controls--thus no relaxation in the 
stringency of these budgets has been demonstrated to be warranted based 
on feasibility, necessity, or impossibility. The EGU economic modeling 
discussed in the RIA illustrates that many sources identified as 
currently having SCR retrofit potential elect not to install a SCR, and 
those that do retrofit SCR make no such installation until 2030. Yet, 
the fleet is able to comply with 2026 state emissions budgets (whose 
emissions reductions are premised in large part on assumed SCR 
retrofits) through reduced utilization (many of these units are 
projected to retire, and thus reduce emissions). While these changes in 
coal fleet utilization are not required or imposed through the EPA's 
state emissions budgets, they are projected to be an economic 
preference for a substantial portion of the unretrofitted fleet owing 
to future market and policy conditions. If sources do ultimately elect 
this pathway, then compliance will occur with significantly less demand 
on SCR retrofit labor and material markets than assumed at Step 3. The 
daily emissions rates are a backstop to the broader emissions reduction 
requirements, which we view as an important and necessary component to 
the elimination of significant contribution. But we also recognize that 
the objectives to be accomplished by the backstop must be balanced with 
larger economic and environmental conditions facing EGUs for which a 
deferral of the backstop rate ultimately is the most reasonable 
approach given these competing concerns. See Wisconsin, 938 F.3d at 320 
(``EPA, though, possesses a measure of latitude in defining which 
upwind contribution `amounts' count as `significant[ ]' and thus must 
be abated.''). As noted in section VI.B.1.d of this document, the EPA 
finds that as long as state emissions budgets continue to reflect the 
required degree of emissions reductions at least for an interim period 
until the backstop rate would apply more uniformly, deferral of the 
backstop rate requirement for uncontrolled units in recognition of the 
transition period identified by commenters can be justified on the 
basis of the greater long-term environmental benefits obtained through 
greater compliance flexibility.
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, 906-08 (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.\340\ Both of the exceedances by Missouri 
sources could easily have been avoided if the owner and operator of 
several SCR-equipped,

[[Page 36798]]

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, the 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 the 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.
---------------------------------------------------------------------------

    \340\ Information on the assurance level exceedances in the 
2019, 2020, and 2021 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); 87 FR 57695 (September 21, 2022).
---------------------------------------------------------------------------

    To correct the deficiency in the regulatory requirements, the EPA 
in this rulemaking is revising the Group 3 trading program regulations 
to establish an additional emissions limitation to more effectively 
deter avoidable assurance level exceedances starting with the 2024 
control period. Because the pollutant involved is ozone season 
NOX and the particular sources for which deterrence is most 
needed are located in states that are transitioning from the Group 2 
trading program to the Group 3 trading program, the EPA is promulgating 
the strengthening provisions as revisions to the Group 3 trading 
program regulations rather than the Group 2 trading program 
regulations.\341\
---------------------------------------------------------------------------

    \341\ 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 doing 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.
---------------------------------------------------------------------------

    The two historical 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 instead adding a new, unit-level emissions limitation 
structured as a prohibition to emit NOX in excess of a 
defined amount. A violation of the prohibition will not trigger 
additional allowance surrender requirements beyond the surrender 
requirements that would otherwise apply, but will trigger the possible 
application of the CAA's enforcement authorities. The new emissions 
limitation will be in addition to, not in lieu of, the other 
requirements of the Group 3 trading program. This point is being 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.'')
    Because the purpose of the new unit-level secondary emissions 
limitation is to deter conduct causing exceedances of a state's 
assurance level, the EPA is conditioning 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 will 
be carried out according to the existing assurance provision procedures 
and will 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. To ensure that the secondary 
emissions limitation is focused on units where the need for improved 
incentives is greatest, and also to ensure that the limitation will not 
apply to units used only to meet peak electricity demand, the 
limitation applies only to units that are equipped with post-combustion 
controls (i.e., SCR or SNCR) and that operated for at least ten percent 
of the hours in the control period in question and in at least one 
previous control period.
    For units to which a secondary emissions limitation applies in a 
given control period based on the conditions just summarized, the 
limitation is defined by a formula in the regulations. The formula is 
generally designed to compute the potential amount the unit would have 
emitted during the control period, given its actual heat input during 
the control period, if the unit had achieved an average emissions rate 
equal to the unit's lowest average emissions rate in a previous control 
period plus a margin of 25 percent. To ensure that the data used to 
establish the unit's lowest previous average emissions rate are 
representative and of high quality, only past control periods where the 
unit participated in a CSAPR trading program for ozone season 
NOX and operated in at least ten percent of the hours in the 
control period are considered. Further, to avoid causing units that 
achieve emissions rates lower than 0.08 lb/mmBtu from becoming subject 
to more stringent secondary emissions limitations in subsequent control 
periods, the secondary emissions limitation formula uses a

[[Page 36799]]

floor emissions rate of 0.10 lb/mmBtu (which is 0.08 lb/mmBtu plus the 
formula's 25 percent margin). In addition to making sure that 
performance better than 0.08 lb/mmBtu is not disincentivized, the 
inclusion of the floor emissions rate also ensures that no unit 
achieving an average emissions rate of 0.10 lb/mmBtu or less in a given 
control period will exceed a secondary emissions limitation in that 
control period. Finally, the formula includes a 50-ton threshold, which 
will avert violations for small performance deviations at large EGUs 
and also ensure that no unit emitting less than 50 tons in a given 
control period will exceed a secondary emissions limitation in that 
control period.
    In summary, a secondary emissions limitation is applicable to a 
unit for a given control period only if the state's assurance level is 
exceeded, responsibility for the exceedance is apportioned at least in 
part to the set of units represented by the unit's designated 
representative, the unit is equipped with post-combustion controls, and 
the unit operated for at least ten percent of the hours in the control 
period. Where a secondary emissions limitation applies to a unit for a 
given control period, the amount of the limitation is computed as the 
sum of 50 tons plus the product of (1) the unit's heat input for the 
control period times (2) a NOX emissions rate of 0.10 lb/
mmBtu or, if higher, 125 percent times the lowest seasonal average 
NOX emissions rate achieved by the unit in a previous 
control period when the unit participated in a CSAPR trading program 
for ozone season NOX emissions and operated in at least ten 
percent of the hours in the control period.\342\
---------------------------------------------------------------------------

    \342\ For the actual regulatory language, see 40 CFR 97.1025(c) 
as added by this rule.
---------------------------------------------------------------------------

    Table VI.B.8-1 shows the secondary emissions limitations that the 
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 2020 and 2021 when assurance level 
exceedances occurred in Missouri. Following consideration of comments, 
the EPA believes that in each case the formula functions in a 
reasonable manner, and the Missouri 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 
VI.B.8-1 does not show any units that would have been identified as 
subject to secondary emissions limitations in the case of the 2019 and 
2020 assurance level exceedances in Mississippi because no units in the 
state meeting all conditions for applicability--including the 
requirement to be equipped with post-combustion controls--exceeded 
their respective limitations.

          Table VI.B.8-1--Illustrative Results of Applying Secondary Emissions Limitation in Previous Instances of Assurance Level Exceedances
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  125% of Lowest
                                                                                    previously       Actual NOX     Secondary   Actual NOX
                Owner/operator                               Unit                  achieved NOX    emissions rate   emissions    emissions   Exceedance
                                                                                  emissions rate     (lb/mmBtu)     limitation    (tons)       (tons)
                                                                                    (lb/mmBtu)                        (tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     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 secondary 
emissions limitation formula to other units in the states 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 VI.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 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 secondary emissions limitation provisions are being finalized 
as proposed except for the addition of the condition that a unit to 
which the provisions apply must be equipped with post-combustion 
controls. The EPA's responses to comments concerning the secondary 
emissions limitation provisions, including the comments giving rise to 
the change just mentioned, are in the remainder of this section and 
section 5 of the RTC document.
    Comment: Some commenters stated that the secondary emissions 
limitation is not necessary, or would be a disproportionate remedy, 
because experience shows that exceedances of the assurance level have 
been rare, and where exceedances of a state's assurance level have 
occurred, the 3-for-1 surrender ratio under the existing regulations 
has applied, providing a sufficient remedy.
    Response: The EPA disagrees with these comments. The purpose of the 
assurance provisions in the CSAPR trading programs is to ensure that 
the emissions reductions required to address a state's obligations 
under the Good Neighbor Provision occur ``within the state'' as 
mandated by the CAA. See North Carolina v. EPA, 531 F.3d 896, 906-08 
(D.C. Cir. 2008). Prior to this action, the sole consequence for an 
exceedance of a state's assurance level

[[Page 36800]]

has been a requirement to surrender two additional allowances for each 
ton of the exceedance. The repeated, large, foreseeable, and easily 
avoidable exceedances of Missouri's assurance level under the Group 2 
trading program in 2020 and 2021 have made clear that a remedy based 
solely on additional allowance surrenders is insufficient to address 
this statutory requirement and that a materially stronger deterrent is 
needed.
    Comment: Some commenters stated that the secondary emissions 
limitation could apply to exceedances caused by factors outside the 
control of the EGU operator, going beyond the EPA's intent of deterring 
exceedances that are foreseeable and avoidable. For example, commenters 
pointed out that some units that typically combust gas may sometimes be 
ordered to combust oil at times when supplies of gas are constrained 
and expressed concern that the resulting higher NOX 
emissions could cause a unit to exceed its secondary emissions 
limitation. Another commenter stated that it is not uncommon for units' 
seasonal average NOX emissions rate to vary by more than 25 
percent across control periods.
    Response: The EPA agrees that the secondary emissions limitation is 
intended to apply to units in a position to avert an exceedance of a 
state's assurance level. The contention that year-to-year variability 
of 25 percent in units' seasonal average emissions rates is common is 
not in itself a persuasive reason to omit the secondary emissions 
limitation from the final rule, because the mere existence of such 
variability says nothing about whether the operators of those units 
could reduce that variability through their operational decisions, and 
the commenter provided no data regarding the extent to which the 
historical variability was avoidable. However, the EPA agrees that a 
secondary emissions limitation should be designed to avoid application 
to a unit whose increase in emissions rate was caused by mandated 
combustion of a higher-NOX fuel than the unit's normal fuel. 
Moreover, based on the analysis of the secondary emissions limitation 
formula prepared for the proposal, the EPA has reviewed the 
applicability of the limitation more generally and has determined that 
it should apply only to units with post-combustion controls, which are 
the units with the greatest ability to manage their emissions rates 
through their operating behavior. This modification will avoid 
application of a secondary emissions limitation in situations where a 
unit's increase in seasonal average NOX emissions rate 
relative to past control periods is caused by factors in that control 
period beyond the operator's control, such as being mandated by a 
regulator to combust a higher proportion of oil or operating for a 
higher proportion of hours at load levels where the unit has a higher 
NOX emissions rate for reasons other than non-operation of 
emissions controls.
    Comment: Some commenters asserted that because it is not known if a 
state's assurance level has been exceeded until after the end of the 
control period, EGU operators would be unable to know whether the 
secondary emissions limitation would apply to them during the control 
period. Some of these commenters suggested that where a unit has been 
found to have contributed to an assurance level exceedance, the EPA 
should apply a secondary emissions limitation to the unit not in that 
control period but instead in the following control period.
    Commenters suggested that uncertainty about whether a unit would be 
subject to a secondary emissions limitation could have a variety of 
undesirable consequences. For example, they asserted that some EGUs 
could become unwilling to operate when needed for reliability because 
they would be concerned that merely operating more than in previous 
control periods could cause a unit to exceed its limitation. One 
commenter asserted that the uncertainty would make it difficult for an 
owner of multiple EGUs to use allowances allocated to one EGU to meet 
another EGU's surrender requirements, possibly leading to operating 
restrictions on multiple EGUs.
    Response: The EPA disagrees with these comments. While an operator 
cannot be certain that the secondary emissions limitation will apply to 
a particular EGU until after the end of a control period, the operator 
can be certain that the limitation will not apply to a particular EGU 
simply by ensuring that the unit's seasonal average NOX 
emissions rate does not exceed the higher of 0.10 lb/mmBtu or 125 
percent of the unit's lowest seasonal average NOX emissions 
rate in a previous control period under a CSAPR trading program 
(excluding control periods where the unit operated for less than 10 
percent of the hours). Because any operator of a unit with post-
combustion controls can readily avoid being subject to the limitation, 
there is no need for application of the limitation to be deferred to 
the following control period. Deferral of the limitation's application 
would also have the effect of excusing a unit's first contribution to 
an assurance level exceedance, which the EPA views as inappropriate 
when that exceedance could have been avoided.
    The asserted possible consequences of uncertainty about whether the 
limitation would apply rest on mischaracterizations of the provision. 
The formula for the limitation reflects the unit's actual heat input 
for the control period, so there is no penalty for increased operation 
as long as the unit's seasonal NOX average emissions rate 
stays below the level just referenced. Finally, nothing about the 
secondary emissions limitation disincentivizes an EGU fleet owner from 
transferring allocated allowances among the fleet's EGUs, because 
apportionment of responsibility for an assurance level exceedance--one 
of the conditions for application of the secondary emissions 
limitation--is determined at the level of the group of units 
represented by a common designated representative (typically the set of 
all units operated by a particular owner) rather than the individual 
unit.
    Comment: Some commenters stated that the EPA should revise the 
secondary emissions limitation formula so that where a limitation 
applies to a unit, the unit's previous NOX emissions rate 
used in the formula would not be subject to any floor. These commenters 
also recommended that if the secondary emissions limitation provisions 
are not finalized, the EPA instead should raise the allowance surrender 
ratio applied to exceedances of the assurance level in this final rule.
    Response: The EPA disagrees with the suggestion to remove the 
emissions rate floor from the secondary emissions limitation formula, 
which would have the effect of making the limitation more stringent for 
any unit that has achieved a seasonal average NOX emissions 
rate lower than 0.08 lb/mmBtu in a past control period. As indicated by 
their label, the secondary emissions limitation provisions play a 
secondary role in the Group 3 trading program regulations, specifically 
to provide the strongest possible deterrent against conduct leading to 
foreseeable and avoidable exceedances of a state's assurance level. The 
distinguishing feature of the secondary emissions limitation provisions 
is therefore the remedy for an exceedance, which is potential 
application of the CAA's enforcement authorities. The trading program's 
primary role of achieving required emissions reductions in a more 
flexible and cost-effective manner than command-and-control regulation 
is played by the primary emissions limitation provisions, which are 
structured as allowance surrender requirements. Within this overall

[[Page 36801]]

trading program structure, the EPA considers it sufficient for the 
operation of units at emissions rates lower than 0.08 lb/mmBtu to be 
incentivized through the allowance surrender requirements instead of 
being mandated through potential application of the CAA's enforcement 
authorities.
    The recommendation to raise the allowance surrender ratio 
applicable to exceedances of the assurance level if the secondary 
emissions limitation is not finalized is moot because the secondary 
emissions limitation is being finalized.
9. Unit-Level Allowance Allocation and Recordation Procedures
    In this rule, the EPA is establishing 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. Like the allocation 
processes established in CSAPR, the CSAPR Update, and the Revised CSAPR 
Update, the revised allocation process finalized in this rule is 
designed to provide default allowance allocations to all units that are 
subject to allowance holding requirements. The EPA's allocations and 
allocation procedures apply for the 2023 control period \343\ and, by 
default, for subsequent control periods unless and until a state or 
tribe provides state-determined or tribe-determined allowance 
allocations under an approved SIP revision or tribal implementation 
plan.\344\
---------------------------------------------------------------------------

    \343\ The rule does not include an option for states to replace 
the EPA's unit-level allocations for the 2023 control period because 
the Agency believes a process for obtaining appropriately authorized 
allowance allocations determined by a state or tribe could not be 
completed in time for those allocations to be recorded before the 
end of the 2023 control period.
    \344\ The options for states to submit SIP revisions that would 
replace the EPA's default allowance allocations are discussed in 
sections VI.D.1, VI.D.2, and VI.D.3 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 the EPA's default 
allocations for subsequent control periods.
---------------------------------------------------------------------------

    The default allocation process for the Group 3 trading program as 
updated in this rule involves three main steps. First, portions of each 
state emissions budget for each control period are reserved for 
potential allocation to units that are subject to allowance holding 
requirements and that might not otherwise receive allowance allocations 
in the overall allocation process, including both ``existing'' units in 
any areas of Indian country not subject to a state's CAA implementation 
planning authority as well as ``new'' units anywhere within a state's 
borders.\345\ Second, in advance of each control period, the unreserved 
portion of the state budget is allocated among the state's eligible 
existing units, any portion of the state budget reserved for existing 
units in Indian country not subject to the state's CAA implementation 
planning authority is allocated among those units, 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 portion of the budget reserved for new 
units 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.
---------------------------------------------------------------------------

    \345\ Under this rule, the unit-level allocations to 
``existing'' units are generally computed in the year before the 
year of each control period, and the determination of whether to 
treat a particular unit as existing for purposes of that control 
period's allocations is made as part of the allocation process, 
generally based on whether the Agency has the data needed to compute 
an allocation for the unit as an existing unit. A unit that is 
subject to allowance holding requirements for a given control period 
and that did not receive an allocation for that control period as an 
existing unit is generally eligible to receive an allocation from 
the portion of the budget reserved for ``new'' units. For further 
discussion of which units are considered eligible for allocations as 
existing units or new units in particular control periods, see 
sections VI.B.9.b and VI.B.9.c.
---------------------------------------------------------------------------

    While the overall three-step allocation process summarized in this 
section was also followed in CSAPR, the CSAPR Update, and the Revised 
CSAPR Update, in this rule the EPA is making revisions to each step to 
better address units in Indian country and to better coordinate the 
unit-level allocation process with the dynamic budget-setting process 
discussed in section VI.B.4 of this document. The revisions to the 
three steps are discussed in sections VI.B.9.a, VI.B.9.b, and VI.B.9.c, 
respectively.
a. Set-Asides of Portions of State Emissions Budgets
    The first step of the overall unit-level allocation process for a 
given control period involves reserving portions of each state's budget 
for the control period in ``set-asides.'' In this rule, the EPA is 
making several revisions affecting the establishment of set-asides. The 
first revision, which is largely unrelated to the other aspects of this 
rulemaking, will update the regulations for the Group 3 trading program 
\346\ 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.\347\ Consistent 
with this holding, the EPA is revising language in the Group 3 trading 
program regulations that prior to this rule, for purposes of allocating 
allowances from a given state's emissions budget, distinguished 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 now 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 
more accurately distinguishes 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 revision is that any 
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 will 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.\348\
---------------------------------------------------------------------------

    \346\ As discussed in section VI.B.13, the EPA is also making 
this revision to the regulations for the other CSAPR trading 
programs in addition to the Group 3 trading program.
    \347\ 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 III.C.2.
    \348\ The EPA notes that the units that will be treated for 
allocation purposes in the same manner as units not in Indian 
country will 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 III.C.2).
---------------------------------------------------------------------------

    The remaining revisions, which are interrelated, concern the types 
of set-asides that in the context of this rule will best accomplish the 
goal of ensuring the availability of allocations to units that are 
subject to allowance holding requirements and that would

[[Page 36802]]

not otherwise receive allowance allocations. One 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 rule will 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. To provide an option for Utah (or a 
similarly situated state in the future) to replace the Agency'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, which is not 
subject to the state's jurisdiction or control (or similarly situated 
units in the future), the EPA is revising 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 set 
of units within a state's borders eligible to receive allocations as 
existing units includes one or more units \349\ in an area of Indian 
country not covered by the state's CAA implementation planning 
authority, the EPA will 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 will 
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 VI.B.9.b of this document). 
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 later in this section), the EPA 
will 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 will have no substantive effect unless and until the 
relevant state chooses to replace the 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.\350\ The EPA believes the 
establishment of Indian country existing unit set-asides accomplishes 
the objective of allowing states to control allowance allocations to 
units covered by their CAA implementation planning authority while 
ensuring that the allocations to units in Indian country not covered by 
such authority remain under Federal authority (unless replaced by a 
tribal implementation plan).
---------------------------------------------------------------------------

    \349\ In coordination with the dynamic budgeting process 
discussed in section VI.B.4, each unit included in the unit 
inventory used to determine a state's dynamic emissions budget for a 
given control period in 2026 or a later year will be considered an 
``existing'' unit for that control period for purposes of the 
determination of unit-level allowance allocations. In other words, 
there will no longer be a single fixed date that divides 
``existing'' from ``new'' units.
    \350\ As noted in section VI.D, 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 Group 3 trading program 
regulations as in effect before this rule, allowances for new units 
have been provided from separate new unit set-asides and Indian country 
new unit set-asides. Under this rule, the EPA is combining 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 will continue to administer the new unit set-asides in the 
event a state chooses to replace the 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 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. 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.\351\ 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 the EPA's default allocations to existing units with 
state-determined allocations, because otherwise the EPA would be unable 
to maintain Federal implementation authority and ensure that the units 
in Indian country would receive an appropriate share of any reallocated 
allowances.\352\ The principal difference between the new unit set-
asides and the Indian country new unit set-asides under the regulations 
in effect before this rule was that, if a state chose to replace the 
EPA's default allocations with state-determined allocations, the state 
would take over administration of the new unit set-aside, but not any 
Indian country new unit set-aside.

[[Page 36803]]

Under the revised regulations finalized in this rule, states will not 
be able to take over administration of the new unit set-asides in this 
situation. Therefore, there is no longer any reason to establish 
separate Indian country new unit set-asides in order to preserve 
Federal (and potentially tribal) authority to implement the rule in 
areas of Indian country subject to tribal jurisdiction.
---------------------------------------------------------------------------

    \351\ Under the regulations in effect before this final rule, 
allowances from an Indian country new unit set-aside that are not 
allocated to qualifying new units in Indian country are first 
transferred to the state's new unit set-aside, and if the allowances 
are not allocated to qualifying new units elsewhere within the 
state's borders, the allowances are then reallocated to the state's 
existing units.
    \352\ 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 will be set 
aside for potential allocation to new units from the emissions budgets 
for each state, for the control periods in 2023 through 2025 (but not 
for subsequent control periods, as discussed later in this section), 
the EPA is establishing 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 base 2 percent of the state 
emissions budget to address any unknown new units, with a minimum total 
amount of 5 percent. For example, if planned units in a state are 
projected to emit 4 percent of the state's NOX ozone season 
emissions budget, then the new unit set-aside for the state would be 
set at 6 percent, which is the sum of the 4 percent for planned units 
plus the base 2 percent for unknown new units. Alternatively, if 
planned new units are projected to emit only 1 percent of the state's 
budget, the new unit set-aside would be set at the minimum 5 percent 
amount. Except for the addition of the 5 percent minimum, which is a 
change being made in response to comments, the approach to setting the 
new unit set-aside amounts is generally 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, the EPA is making an exception 
for New York for the 2023 through 2025 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.
    The final regulations issued under this rule specify the new unit 
set-aside amounts in terms of the percentages of the state emissions 
budgets. The amounts are shown in Tables VI.B.9.a-1, VI.B.9.a-2, and 
VI.B.9.a-3 of this document show the tonnage amounts of the new unit 
set-asides for the control periods in 2023 through 2025 that are 
computed by multiplying the new unit set-aside percentages by the 
preset budgets finalized in this rule for those control periods. The 
amounts of the 2023 new unit set-asides are illustrative because they 
do not reflect the impact of transitional adjustments included in the 
rule that that are likely to affect the 2023 budgets as 
implemented.\353\ The amounts of the 2024 and 2025 new unit set-asides 
are the actual amounts, because the 2024 and 2025 budgets computed in 
this rule are the budgets that will be implemented, without any need 
for transitional adjustments.
---------------------------------------------------------------------------

    \353\ As discussed in section VI.B.12, the EPA expects that this 
final rule will become effective after May 1, 2023, causing the 
emissions budgets for the 2023 control period to be adjusted under 
the rule's transitional provisions so as to ensure that the new 
budgets will apply only after the rule's effective date. The actual 
new unit set-asides for the 2023 control period will be computed 
using the adjusted budgets, but the 2023 budget amounts shown in 
Table VI.B.9.a-1 do not reflect these adjustments.

  Table VI.B.9.a-1--Illustrative CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for the 2023
                                                 Control Period
----------------------------------------------------------------------------------------------------------------
                                                                                   New unit set-   New unit set-
                              State                                  Emissions     aside amount    aside amount
                                                                  budgets (tons)     (percent)        (tons)
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................           6,379               5             319
Arkansas........................................................           8,927               5             446
Illinois........................................................           7,474               5             374
Indiana.........................................................          12,440               5             622
Kentucky........................................................          13,601               5             680
Louisiana.......................................................           9,363               5             468
Maryland........................................................           1,206               5              60
Michigan........................................................          10,727               5             536
Minnesota.......................................................           5,504               5             275
Mississippi.....................................................           6,210               5             311
Missouri........................................................          12,598               5             630
Nevada..........................................................           2,368               9             213
New Jersey......................................................             773               5              39
New York........................................................           3,912               5             196
Ohio............................................................           9,110               6             547
Oklahoma........................................................          10,271               5             514
Pennsylvania....................................................           8,138               5             407
Texas...........................................................          40,134               5           2,007
Utah............................................................          15,755               5             788
Virginia........................................................           3,143               5             157
West Virginia...................................................          13,791               5             690
Wisconsin.......................................................           6,295               5             315
----------------------------------------------------------------------------------------------------------------


[[Page 36804]]


 Table VI.B.9.a-2--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.........................................................           6,489               5             324
Arkansas........................................................           8,927               5             446
Illinois........................................................           7,325               5             366
Indiana.........................................................          11,413               5             571
Kentucky........................................................          12,999               5             650
Louisiana.......................................................           9,363               5             468
Maryland........................................................           1,206               5              60
Michigan........................................................          10,275               5             514
Minnesota.......................................................           4,058               5             203
Mississippi.....................................................           5,058               5             253
Missouri........................................................          11,116               5             556
Nevada..........................................................           2,589               9             233
New Jersey......................................................             773               5              39
New York........................................................           3,912               5             196
Ohio............................................................           7,929               6             476
Oklahoma........................................................           9,384               5             469
Pennsylvania....................................................           8,138               5             407
Texas...........................................................          40,134               5           2,007
Utah............................................................          15,917               5             796
Virginia........................................................           2,756               5             138
West Virginia...................................................          11,958               5             598
Wisconsin.......................................................           6,295               5             315
----------------------------------------------------------------------------------------------------------------


 Table VI.B.9.a-3--CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for the 2025 Control Period
----------------------------------------------------------------------------------------------------------------
                                                                                   New unit set-   New unit set-
                              State                                  Emissions     aside amount    aside amount
                                                                  budgets (tons)     (percent)        (tons)
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................           6,489               5             324
Arkansas........................................................           8,927               5             446
Illinois........................................................           7,325               5             366
Indiana.........................................................          11,413               5             571
Kentucky........................................................          12,472               5             624
Louisiana.......................................................           9,107               5             455
Maryland........................................................           1,206               5              60
Michigan........................................................          10,275               5             514
Minnesota.......................................................           4,058               5             203
Mississippi.....................................................           5,037               5             252
Missouri........................................................          11,116               5             556
Nevada..........................................................           2,545               9             229
New Jersey......................................................             773               5              39
New York........................................................           3,912               5             196
Ohio............................................................           7,929               6             476
Oklahoma........................................................           9,376               5             469
Pennsylvania....................................................           8,138               5             407
Texas...........................................................          38,542               5           1,927
Utah............................................................          15,917               5             796
Virginia........................................................           2,756               5             138
West Virginia...................................................          11,958               5             598
Wisconsin.......................................................           5,988               5             299
----------------------------------------------------------------------------------------------------------------

    For control periods in 2026 and later years, the EPA will allocate 
a total of 5 percent 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 will 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 is being codified in the Group 3 trading 
program regulations and will reflect the same percentage of the 
emissions budget for all states.
    The purpose of the change to the procedure for establishing the 
amounts of the set-asides is to coordinate with the dynamic budget-
setting process that may be used to determine budgets beginning with 
the 2026 control period. As discussed in section VI.B.4 of this 
document, under the dynamic budget-setting process, each state's budget 
for each control period will be computed using fleet composition 
information and the total ozone season heat input reported by all 
affected units in the state

[[Page 36805]]

for the most recent control periods before the budget-setting 
computations. (For example, 2026 emissions budgets would be based on 
2022-2024 state-level heat input data.) Moreover, as discussed in 
section VI.B.9.b of this document, the set of units eligible to receive 
allocations as ``existing'' units in a given control period will 
generally be the set of units that operated in the control period two 
years earlier (with the exception of any units whose monitor 
certification deadlines fell after the start of that earlier control 
period). Consequently, by the 2025 control period, all or almost all 
units that commenced commercial operation before issuance of this rule 
will be considered ``existing'' units for purposes of budget-setting 
and allocations, and units commencing commercial operation after 
issuance of this rule generally will 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 will 
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 it is unnecessary to establish set-
aside percentages for some states that are permanently larger than 5 
percent based solely on the fact that projected emissions from planned 
new units happen to be a somewhat larger proportion of those states' 
overall budgets at the time of this rule's issuance.
    The changes to the structure and amounts of set-asides in this rule 
largely follow the proposal. The EPA received few comments on these 
topics. As noted previously, one commenter expressed the view that if 
the amounts of the new unit set-asides were based on 2 percent of the 
respective states' budgets, the set-asides would be too small in 
certain circumstances, and in response the final rule bases the amounts 
of the set-asides on a floor percentage of 5 percent instead of 2 
percent. The remaining commenters expressed a concern that the final 
rule's provisions regarding set-asides should ensure that any tribal 
decisions relating to allowance allocations would not be constrained by 
state decisions. The EPA had this same concern in mind when designing 
the rule and believes that the final set-aside structure--encompassing 
Indian country existing unit set-asides as well as EPA-administered new 
unit set-asides for sources in all areas within each state's borders--
fully addresses the concern, is equitable, and preserves Federal and 
tribal authority under this rule for areas of Indian country subject to 
tribal jurisdiction. The comments and the EPA's responses are discussed 
in greater detail in section 1 of the RTC document.
b. Allocations to Existing Units, Including Units That Cease Operation
    In conjunction with the new and revised state emissions budget-
setting methodology for the Group 3 trading program finalized in this 
rulemaking, the EPA is necessarily establishing a revised procedure for 
making unit-level allocations of Group 3 allowances to existing 
units.\354\ The procedure that the EPA is employing 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 procedure for determining allocations from each state emissions 
budget for each control period are described in detail in the Unit-
Level Allowance Allocations Final Rule TSD. The steps are summarized in 
the following paragraphs, with changes from the procedure followed in 
the Revised CSAPR Update noted.
---------------------------------------------------------------------------

    \354\ The 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 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 identifies the list of units eligible to 
receive allocations for the control period. The unit inventories used 
to compute unit-level allocations for the control periods in 2023 
through 2025 are the same inventories that have been used to determine 
the preset emissions budget for these control periods. These 
inventories have been determined in this rulemaking in essentially the 
same manner as in the Revised CSAPR Update. The procedures for updating 
the unit inventories for these control periods are discussed in section 
VI.B.4 of this document, 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 V.B of this document and in the 
Ozone Transport Policy Analysis Final Rule TSD.
    The unit inventories used to compute unit-level allocations for 
control periods in 2026 and later years will 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 2026 budgets 
and allocations will reflect reported data up through the 2024 control 
period). These inventories, which are generally the same as the 
inventories used to compute dynamic budgets for each control period, 
include any unit whose monitor certification deadline was no later than 
the start of the relevant historical control period and that reported 
emissions data during the relevant historical control period. The EPA 
notes that basing the list of eligible units on the list of units that 
reported heat input in the control period two years earlier than the 
control period for which allocations are being determined represents a 
revision to the Group 3 trading program regulations as in effect before 
this rule concerning the treatment of allocations to retired units. 
Under the prior regulations, units that cease operations for two 
consecutive control periods would continue to receive allocations as 
existing units for three additional years (that is, a total of five 
years) before the allowances they would otherwise have received are 
reallocated to the new unit set-aside for the state. Under the 
regulations as revised in this rule, units that cease operation will 
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 that anticipated market conditions 
(in particular, the incentives toward power sector transition to 
cleaner generating sources), particularly in the later 2020s, 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 will 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 will 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 will also determine 
the maximum total NOX emissions value over the 5-year 
period. For coal-

[[Page 36806]]

fired units of 100 MW or larger, the EPA will further determine a 
``maximum controlled baseline'' NOX emissions value, 
computed as the unit's maximum heat input over the 5-year period times 
a NOX emissions rate of 0.08 lb/mmBtu. The maximum 
controlled baseline will serve as an additional cap on unit-level 
allocations for all such coal-fired units starting with the control 
periods in which the assumed use of SCR controls at the units is 
reflected in the state emissions budgets. Thus, the maximum controlled 
baseline will apply for purposes of allocations to units with existing 
SCR controls for all control periods starting with the 2024 control 
period and for all other coal-fired units of 100 MW or more (except 
circulating fluidized bed units) starting with the 2027 control period. 
These procedures are nearly identical to the procedures used in the 
Revised CSAPR Update, with three exceptions. First, instead of using 
only the data available at the time of the rulemaking, for each control 
period the EPA will use data from the most recent five control periods 
for which data had been reported. (For example, for the 2026 control 
period, the EPA will use data for the 2020-2024 control periods.) 
Second, to simplify the data compilation process, the EPA will 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. Third, the use of the maximum controlled baseline as an 
additional cap on emissions is a change adopted in this rule in 
response to comments received on the proposal. Specifically, commenters 
observed that if a state's emissions budget is decreased to reflect an 
assumption that a particular unit in the state is capable of reducing 
its emissions through the installation of new SCR controls, but the 
historical emissions cap applied to that unit in the unit-level 
allocation methodology does not reflect use of the new controls, then 
the allocation methodology could have the effect of reducing unit-level 
allocations to the other units in the state whose historical emissions 
already reflect use of existing controls rather than the unit assumed 
to install new controls. The EPA agrees with the comment and in this 
rule has added the maximum controlled baseline provision to the 
allocation methodology to mitigate the potential effect identified by 
the commenters.
    In the third step of the procedure for determining allocations to 
existing units in each state, the EPA will 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 or, if applicable, the unit's maximum controlled 
baseline. If the allocations to one or more units are curtailed because 
of the units' applicable caps, the EPA will iterate the calculation 
procedure as needed to allocate the remaining allowances, excluding 
from each successive iteration any units whose allocations have already 
reached their caps. (If all units in a state reach their caps, any 
remaining allowances are allocated in proportion to the units' average 
heat input values, notwithstanding the caps.) This calculation 
procedure is identical to the calculation procedure used in the Revised 
CSAPR Update (as well as the CSAPR Update and CSAPR), but using caps 
that reflect both the units' maximum historical NOX values 
and also, where applicable, the maximum controlled baseline values.
    Illustrative unit-level allocations for the 2023 control period and 
final unit-level allocations for the 2024 and 2025 control periods are 
being determined in this rulemaking based on the emissions budgets for 
those control periods also determined in the rulemaking and are 
included in the docket. The 2023 allocations are only illustrative 
because, as discussed in section VI.B.12.a, the EPA expects the 
effective date of the rule to occur after the start of the 2023 control 
period and consequently expects the 2023 control period to be a 
transitional period in which the emissions budgets determined in this 
rulemaking apply only for the portion of the control period occurring 
on and after the rule's effective date, while any previously determined 
emissions budgets apply for the portion of the control period before 
the rule's effective date. The rule's effective date will become known 
when the rule is published in the Federal Register. As soon as 
practicable thereafter, the EPA will calculate the final prorated or 
blended 2023 state emissions budgets and 2023 unit-level allocations 
based on the transitional formulas finalized in this action (see 
section VI.B.12.a of this document) and will communicate the 
information to the public through a notice of data availability. The 
2023 and 2024 allocations will then be recorded 30 days after the 
effective date of the final rule (to provide an interval in which to 
execute the recall of 2023 and 2024 Group 2 allowances, as discussed in 
section VI.B.12.c of this document), while the 2025 allocations will be 
recorded by July 1, 2024.\355\
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    \355\ The recordation schedule for the 2023 and 2024 allocations 
represents an expected acceleration of the recordation schedule in 
effect immediately before this final rule, which called for 
allocations of 2023 and 2024 Group 3 allowances to existing units to 
be recorded by September 1, 2023. See Deadlines for Submission and 
Recordation of Allowance Allocations Under the Cross-State Air 
Pollution Rule (CSAPR) Trading Programs and the Texas SO2 
Trading Program (the ``Recordation Rule''), 87 FR 52473 (August 26, 
2022).
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    The default unit-level allocations for each control period in 2026 
or a later year will be computed immediately following the 
determination of the state emissions budgets for the control period. 
The EPA will perform the 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. There 
will be a 30-day period in which objections to the data and preliminary 
computations may be submitted, and the EPA will then make any 
appropriate revisions and issue another notice of data availability by 
May 1 of the year before the control period. The EPA will then record 
the allocations by July 1 of the year before the control period.\356\
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    \356\ The current recordation schedule, which provides for 
almost all allowance allocations to existing units for a given 
control period under all the CSAPR trading programs to be recorded 
by July 1 of the year before the year of that control period, was 
adopted in the Recordation Rule.
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    All covered states also have options to establish state-determined 
allowance allocations for control periods in 2024 and later years. As 
discussed in section VI.D.1 of this rule, a state choosing to establish 
state-determined allocations for the 2024 control period would need to 
submit a letter of intent to the EPA by August 4, 2023, and would need 
to submit the SIP revision with the allocations by September 1, 2023. 
The EPA would defer recordation of the 2024 allocations for the state's 
sources until March 1, 2024, to provide time for this process to be 
completed. As discussed in sections VI.D.2 and VI.D.3 of this rule, a 
state choosing to establish state-determined allocations for control 
periods in 2025 and later years would need to submit a SIP revision by 
December 1 of the year two years before the first year for which state-
determined allocations are being established--e.g., by December 1, 
2023, for allocations for the 2025 control period--and would need to 
submit the allocations for each control period by June 1 of the year 
before the control period--e.g., by June 1, 2024, for allocations for 
the 2025

[[Page 36807]]

control period.\357\ The EPA would record any state-determined 
allocations for control periods in 2025 and later years 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 unit-
level allocations.
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    \357\ The current deadlines for states to submit state-
determined allowance allocations to the EPA were adopted in the 
Recordation Rule and are coordinated with the schedule for 
computation of state emissions budgets for control periods in 2026 
and later years. For example, for the 2026 control period, by May 1, 
2025, the EPA will publish the final state emissions budgets and the 
EPA's default unit-level allocations; by June 1, 2025, states will 
submit any state-determined unit-level allocations that would 
replace the default allocations; and by July 1, 2025, the EPA will 
record the default unit-level allocations or the state-determined 
unit-level allocations, as applicable, in sources' compliance 
accounts.
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    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--the EPA will follow the 
states' methodologies to the extent possible in developing the EPA's 
allocations of Group 3 allowances to the units in those states for the 
control periods in 2023 through 2025.\358\ The EPA will not follow any 
state-specific methodologies as part of the procedures for determining 
default unit-level allocations of Group 3 allowances for control 
periods in 2026 or later years. However, like other states, these three 
states have options to replace the EPA's default allocations with 
state-determined allocations through SIP revisions starting with the 
2024 control period.
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    \358\ For discussion of how the EPA is using the previously 
approved allocation methodologies for Alabama, Indiana, and New York 
to determine allocations to units in these states for the 2023-2025 
control periods, see the Allowance Allocation Final Rule TSD.
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    As an exception to all of the recordation deadlines that would 
otherwise apply, the EPA will 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 provisions governing allocations to existing units are being 
finalized substantially as proposed, except for the addition of an 
additional cap on unit-level allocations in response to comments. The 
EPA's responses to comments on the unit-level allocation provisions for 
existing units are in section 5 of the RTC document.
c. Allocations From Portions of State Emissions Budgets Set Aside for 
New Units
    The Group 3 trading program regulations provide for the EPA to 
allocate allowances from each new unit set-aside after the end of the 
control period at issue. 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. Thus, in addition to units that have not yet 
completed two full control periods of operation since their monitor 
certification deadlines, units eligible for allocations from the new 
unit set-asides may also include existing coal-fired units that first 
lose their eligibility for allocations from the unreserved portion of 
the applicable state budget by ceasing operation, and then resume 
operation in a later control period. The regulations call for the EPA 
to allocate allowances to any eligible ``new'' units in the state 
generally 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. However, in the case of a unit whose allocation for the 
control period would have been subject to a maximum controlled baseline 
if the unit was eligible to receive allocations as an existing unit, 
the unit's allocation from the new unit set-aside will not exceed a cap 
equal to the unit's reported heat input for the control period times an 
emissions rate of 0.08 lb/mmBtu.
    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.
    This EPA notes that the 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 5 percent of the 
respective state emissions budgets for the respective control periods. 
This limit on growth of the 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 full control periods (and possibly a partial 
control period before those two control periods) before the unit 
becomes eligible to receive allocations as an ``existing'' unit 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 VI.D.2 and VI.D.3 
of this document, 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 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.
    The final rule's provisions concerning unit-level allocations from 
the new unit set-asides are unchanged from the proposal except for the 
addition of the allocation cap in a given control period for any unit 
that would have been subject to a maximum controlled baseline if the 
unit was eligible to receive an allocation as an existing unit

[[Page 36808]]

for that control period.\359\ This change was made to address the same 
comments discussed in section VI.B.9.b of this document that caused the 
Agency to add the maximum controlled baseline provision to the 
procedure for allocating allowances to existing units. The Agency did 
not receive any other comments on the proposed provisions concerning 
unit-level allocations of allowances from the new unit set-asides.
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    \359\ As discussed in section IX.B of this rule, the EPA is 
relocating some of the regulatory provisions relating to 
administration of the new unit set-asides and is also removing 
certain provisions that are made obsolete by revisions to other 
provisions of the Group 3 trading program regulations.
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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 provisions as 
in effect prior to this rule have generally called 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 
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 is therefore finalizing revisions to provide 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) will be 
transferred to a surrender account instead of being reallocated to 
other units in the state. The EPA received no comments on this proposed 
revision, which is being finalized as proposed.
10. 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. Under 40 CFR part 75, a given unit may have several 
options for monitoring and reporting. Any unit can use CEMS. Qualifying 
gas- or oil-fired units can use certain excepted monitoring 
methodologies that rely in part on fuel-flow metering in combination 
with CEMS-based or testing-based NOX emissions rate data. 
Certain non-coal-fired, low-emitting units can use a low mass emissions 
(LME) methodology, and sources can seek approval of alternative 
monitoring systems approved by the Administrator through a petition 
process. 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 
quarterly reports will contain all the data required concerning ozone 
season NOX emissions under the Group 3 trading program.
    In this rulemaking, as proposed, the EPA is making two changes to 
the Group 3 trading program's previous requirements related to 
monitoring, recordkeeping, and reporting. First, the EPA is revising 
the monitor certification deadline in the Group 3 trading program 
regulations applicable to certain units that have not already certified 
monitoring systems for use under 40 CFR part 75. This revision is 
expected to provide approximately 15 EGUs in Nevada and Utah with 180 
days following the rule's effective date to certify monitoring systems, 
with the consequence that the units are expected to become subject to 
allowance holding requirements under the Group 3 trading program 
starting with the 2024 control period. Second, to implement the trading 
program enhancements, the EPA is adding certain new recordkeeping and 
reporting requirements, which will be implemented through amendments to 
the regulations in 40 CFR part 75 and will apply starting January 1, 
2024. Sources generally will be able to meet the additional 
recordkeeping and reporting requirements using the data that are 
already collected by their current monitoring systems, and the EPA is 
not requiring the installation of additional monitoring systems at any 
source. However, a small number of sources with common stacks could 
find it advantageous to upgrade their monitoring systems so as to 
monitor at the individual units instead of monitoring at the common 
stack. The Group 3 trading program monitor certification deadline 
revisions and the additional recordkeeping and reporting requirements 
are discussed in sections VI.B.10.a and VI.B.10.b, respectively.\360\
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    \360\ The EPA is not amending 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 additional 
recordkeeping and reporting requirements will also apply year-round, 
while for units that are allowed and elect to report other data on 
an ozone season-only basis, the additional requirements will also 
apply for the ozone season only.
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a. Monitor Certification Deadlines
    In general, a unit subject to the Group 3 trading program must 
monitor and report emissions data using certified monitoring systems 
starting as of the date the unit enters the trading program or, if 
later, 180 days after the unit commences commercial operation. Where an 
EGU has already certified and maintained monitoring systems in 
accordance with 40 CFR part 75 for purposes of another trading program, 
no recertification solely for purposes of entering the Group 3 trading 
program is required. Under these pre-existing provisions of the Group 3 
trading program regulations, nearly all currently operating EGUs 
transitioning to the trading program under this rule are positioned to 
begin monitoring and reporting under the trading program as of their 
dates of entry (or if later, 180 days after they commence commercial 
operation) because of the units' previous requirements to monitor and 
report emissions under other programs including the CSAPR 
NOX Ozone Season Group 2 Trading Program (for

[[Page 36809]]

units in Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Texas, and 
Wisconsin), the CSAPR NOX Annual Trading Program (for units 
in Minnesota), and the Acid Rain Program (for most units in Nevada and 
Utah).
    As discussed in section VI.B.3 of this document, the EPA has 
identified 15 potentially affected units in Nevada and Utah that 
commenced commercial operation more than 180 days before the effective 
date of this rule and that do not currently report emissions data to 
the Agency under 40 CFR part 75.\361\ To ensure that units in this 
situation have sufficient time to certify monitoring systems as 
required under this rule, the final rule establishes a monitoring 
certification deadline of 180 days after the effective date of the rule 
for affected units that are not already required to report emissions 
under 40 CFR part 75 under another program, equivalent 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 will likely fall after the end of 
the 2023 ozone season, with the result that the certification deadline 
will be extended until May 1, 2024, the first day of the 2024 ozone 
season. Because the Group 3 trading program's allowance holding 
requirements apply to a given unit only after that unit's monitor 
certification deadline, the units in this situation consequently will 
become subject to allowance holding requirements as of the 2024 ozone 
season rather than the 2023 ozone season.
---------------------------------------------------------------------------

    \361\ The units are listed in Table VI.B.3-1.
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    The EPA received no comments on the provisions establishing a 
monitor certification deadline 180 days after the effective date of 
this rule for affected units that are not already required to report 
emissions under 40 CFR part 75, and the provisions are being finalized 
as proposed.
b. Additional Recordkeeping and Reporting Requirements
    To facilitate implementation of the backstop daily NOX 
emissions rates for certain coal-fired units, the secondary emissions 
limitations for units contributing to assurance level exceedances, and 
the revised default unit-level allowance allocation procedures, the 
final rule amends 40 CFR part 75 to establish two sets of additional 
recordkeeping and reporting requirements. The first set of additional 
recordkeeping and reporting requirements is specific to the backstop 
daily emissions rate provisions. Starting January 1, 2024, units 
listing coal as a fuel in their monitoring plans, serving generators of 
100 MW or larger, and equipped with SCR controls on or before the end 
of the previous control period (except circulating fluidized bed units) 
will 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 
backstop daily NOX emissions rate. The units will also be 
required to record and report cumulative NOX emissions 
exceeding the backstop daily NOX emissions rate for the 
ozone season and any portion of such cumulative NOX 
emissions exceeding 50 tons. Starting January 1, 2030, the same 
recordkeeping and reporting requirements will apply to all units 
listing coal as a fuel in their monitoring plans and serving generators 
of 100 MW or larger (except circulating fluidized bed units), including 
units not equipped with SCR controls. These data will be used to 
determine the allowance surrender requirements related to the backstop 
daily NOX emissions rates. Implementation of these 
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.
    The second type of additional recordkeeping and reporting 
requirements applies to units exhausting to common stacks. For these 
units, 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 have also 
been required historically to record and report hourly and cumulative 
data on an individual-unit basis, and where necessary they typically 
have computed 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 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 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 provisions, the final rule requires 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 January 1, 2024. To obtain 
the necessary unit-level hourly mass emissions values, the revised 
regulations rule 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 apportionment procedure is very 
similar to the apportionment procedure that most such units already 
apply to compute reported unit-level heat input data. Where sources 
choose to obtain the additional required data values through 
apportionment, implementation of the additional recordkeeping and 
reporting requirements will necessitate a one-time update to the units' 
data acquisition and handling systems but will not require any changes 
to the monitoring systems already needed to meet other requirements 
under 40 CFR part 75.
    For most units sharing common stacks, the EPA expects that the 
reported unit-specific hourly NOX emissions values computed 
through the apportionment procedures will 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, particularly those where SCR-equipped and non-SCR-
equipped coal-fired units share a common stack, unit-level values 
determined through apportionment based on electricity or steam output 
could overstate the reported NOX mass emissions for the SCR-
equipped units and correspondingly understate the reported 
NOX mass emissions for the non-SCR-equipped units.\362\ As 
proposed, the

[[Page 36810]]

final rule leaves in place the existing options under 40 CFR part 75 
for plants to upgrade their monitoring equipment to monitor on a unit-
specific basis instead of at the common stack. Plant owners may find 
this option attractive if they believe it would reduce the quantities 
of reported emissions exceeding the backstop daily emissions rate.
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    \362\ The EPA is aware of five plants in the states covered by 
this rule where SCR-equipped and non-SCR-equipped coal-fired units 
exhaust to a common stack: Clifty Creek in Indiana; Cooper, Ghent, 
and Shawnee in Kentucky; and Sammis in Ohio. The owners of the 
Sammis plant have announced plans to retire the plant in 2023.
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    The EPA is finalizing the additional recordkeeping and reporting 
requirements generally as proposed, with modifications as needed to 
accommodate the changes in the backstop daily emissions rate provisions 
from proposal discussed in sections VI.B.1.c.i and VI.B.1.7. No 
comments were received on the recordkeeping and reporting requirements 
added to facilitate implementation of the backstop daily emissions 
rate. Comments on the requirement to report unit-specific 
NOX emissions data for units sharing common stacks are 
addressed in the following paragraphs.
    Comment: Some commenters claimed that for plants where SCR-equipped 
and non-SCR-equipped coal-fired units share common stacks, the rule as 
proposed would have effectively mandated installation of unit-specific 
monitoring systems in order to comply with the backstop daily emissions 
rate provisions. The commenters generally requested that application of 
the backstop daily rate provisions be delayed for plants with common 
stacks until all units sharing the stacks were subject to the 
provisions. Alternatively, they claimed that the EPA should consider 
the cost of the additional unit-specific monitoring system to be a cost 
of the rule.
    One commenter claimed that the option to install unit-specific 
monitoring systems for the units sharing a common stack at its plant 
was not feasible because of a lack of locations in the units' ductwork 
suitable for installation of the monitoring equipment. Specifically, 
the commenter claimed that EPA Method 1 requires monitoring equipment 
to be located at least eight duct diameters downstream and two duct 
diameters upstream of any flow disturbance and stated that the units 
had no straight runs of ductwork sufficiently long to meet these 
criteria.
    Response: The EPA's response to comments about the application of 
backstop rate requirements to units sharing common stacks is in section 
VI.B.7 of this document. With respect to assertions that the rule 
effectively mandates installation of unit-specific monitoring systems, 
the EPA disagrees. Although the EPA pointed out the option in the 
proposal, anticipating that owners of some units sharing common stacks 
might find it advantageous to upgrade their monitoring systems, the 
final rule does not mandate such upgrades and explicitly provides a 
reporting option that can be used if a plant owner continues to monitor 
only at the common stack. For example, a plant owner might choose not 
to upgrade monitoring systems if the owner does not plan to operate the 
non-SCR-equipped units sharing the stack frequently. Regarding the 
contention that the cost of additional monitoring systems should be 
considered a cost of the rule, the EPA notes that the monitoring cost 
estimates that the Agency regularly develops for 40 CFR part 75 already 
reflect the conservative assumption that all affected units perform 
monitoring on a unit-specific basis.
    With respect to the comment asserting an inability to install unit-
specific monitoring equipment because of a lack of suitable locations, 
the EPA does not believe the commenter has provided sufficient 
information to support the assertion. Although the commenter cites the 
EPA Method 1 location criteria, the CEMS location provisions in 40 CFR 
part 75 do not reference those location criteria but instead reference 
the EPA Performance Specification 2 location criteria, which recommend 
that a CEMS be located at least two duct diameters downstream and a 
half duct diameter upstream from a point at which a change in pollutant 
concentration may occur.\363\ Thus, while the commenter states that its 
units do not have straight runs of ductwork ten duct diameters long, 
the relevant siting criteria actually call for straight runs of 
ductwork only 2.5 duct diameters long, and the commenter has not 
provided information indicating that these criteria could not be met. 
Moreover, even EPA Method 1 does not require monitoring equipment to be 
located eight duct diameters upstream and two duct diameters downstream 
of any flow disturbance. While the method recommends those distances as 
the first option, the method also allows for locations two duct 
diameters upstream and a half duct diameter upstream from any flow 
disturbance, as well as other locations if certain performance criteria 
can be met.\364\
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    \363\ Appendix B to 40 CFR part 60, Performance Specification 2, 
sec. 8.1.2; see also appendix A to 40 CFR part 75, section 1.1.
    \364\ Appendix A-1 to 40 CFR part 60, Method 1, sec. 11.1.
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11. Designated Representative Requirements
    As noted in section VI.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 existing designated representative provisions in the Group 3 
trading program regulations already provide that the 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 have 
participated in the Group 2 trading program and that are transitioning 
to the Group 3 trading program under this rule 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.
    For a source that is newly affected under the Group 3 trading 
program and that is not currently affected under the Group 2 trading 
program, a designated representative who has been duly authorized by 
the source's owners and operators must submit a new or updated 
certificate of representation to the EPA. The EPA will not record any 
Group 3 allowances allocated to a source in the source's compliance 
account until a certificate of representation has been submitted for 
the source. If a source is also affected under other CSAPR trading 
programs or the Acid Rain Program, the same individual must be the 
source's designated representative for purposes of all the programs.
    The EPA did not propose and is not finalizing any changes to the 
designated representative requirements. The EPA received no comments on 
the provisions of the proposal relating to these requirements.
12. Transitional Provisions
    This section discusses several provisions that the EPA will 
implement to address the transition of sources into the Group 3 trading 
program as revised. The purposes of the transitional provisions are 
generally the same as the

[[Page 36811]]

purposes of the analogous transitional provisions promulgated in the 
Revised CSAPR Update: first, addressing the likelihood that the 
effective date of this rule 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.\365\ 
However, the sources that will be participants in the revised Group 3 
trading program under this rule are transitioning from several 
different starting points--with some sources already in the existing 
Group 3 trading program, some sources coming from the Group 2 trading 
program, and some sources not currently participating in any seasonal 
NOX trading program. The EPA is therefore finalizing 
transitional provisions that differ across the sets of potentially 
affected sources based on the sources' different starting points.
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    \365\ As discussed in section VI.B.1.d, the EPA is not creating 
a ``safety valve'' mechanism in this rule analogous to the voluntary 
supplemental allowance conversion mechanism established under the 
Revised CSAPR Update, but intends in the near future to propose and 
take comment on potential amendments to the Group 3 trading program 
that would add an auction mechanism to the regulations for the 
purpose of further increasing allowance market liquidity in 
conjunction with other appropriate changes to ensure program 
stringency is maintained. While these changes may provide an 
additional measure of assurance to the market that allowances will 
be available for compliance to a degree consistent with the Step 3 
emissions control stringency, the EPA does not anticipate that 
market liquidity concerns pose a challenge to the feasibility of 
sources to comply with the Group 3 trading program as finalized in 
this action.
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a. Prorating Emissions Budgets, Assurance Levels, and Unit-Level 
Allowance Allocations in the Event of an Effective Date After May 1, 
2023
    The EPA expects that the effective date of this rule will fall 
after the start of the Group 3 trading program's 2023 control period on 
May 1, 2023, because the effective date of the rule will be 60 days 
after the date of the final rule's publication in the Federal Register. 
The EPA is addressing this circumstance 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.\366\ Variability 
limits, assurance levels, and unit-level allocations for 2023 will all 
be computed using the appropriately prorated emissions budgets 
amounts.\367\
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    \366\ As discussed in sections VI.B.7 and VI.B.8, the revisions 
establishing unit-specific backstop daily emissions rates and, for 
units contributing to assurance level exceedances, secondary unit-
specific emissions limitations, will not take effect until the 2024 
control period or later.
    \367\ The EPA notes that transitional provisions similar to the 
prorating provisions being finalized in this rule were finalized and 
implemented without issue under the Revised CSAPR Update.
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    As discussed in section VI.B.2 of this document, in the case of the 
three 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--Minnesota, Nevada, and Utah--
the sources will begin participating in the Group 3 trading program on 
the later of May 1, 2023, or the rule's effective date. For these 
states, in the rulemaking the EPA has computed the full-season 
emissions budgets that would have applied for the entire 2023 control 
period if the final rule had become effective no later than May 1, 
2023, and were therefore in effect for the entire 153-day control 
period from May 1, 2023, through September 30, 2023. Assuming that the 
final rule becomes effective after May 1, 2023, as expected, the EPA 
will determine prorated emissions budgets for the 2023 control period 
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 for the 2023 control period will be computed by 
first determining for each state the percentage by which the state's 
reported heat input for the full 2023 ozone season (i.e., May 1, 2023 
through September 30, 2023) exceeds the heat input used to compute the 
state's full-season 2023 emissions budget under this rule and then 
multiplying the higher of this percentage or 21 percent by the state's 
prorated emissions budget and rounding to the nearest allowance, 
yielding prorated assurance levels that equal a minimum of 121 percent 
of the prorated emissions budgets. To determine unit-level allocation 
amounts from the prorated emissions budgets, the EPA will apply the 
unit-level allocation procedure described in section VI.B.9 to the 
prorated budgets. All calculations required to determine the prorated 
emissions budgets, the minimum 21 percent variability limits, and the 
unit-level allocations for the 2023 control period will be carried out 
as soon as possible after the EPA learns the rule's effective date. The 
unit-level allocations for both the 2023 and 2024 control periods will 
be recorded in facilities' compliance accounts approximately 30 days 
after the rule's effective date, as discussed in section VI.B.9.b of 
this document.
    In the case of the 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 will 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 will not substantively affect the sources' requirements prior to 
the rule's effective date. For these states, in the rulemaking the EPA 
has computed the full-season emissions budgets that would have applied 
for the entire 2023 control period if the final rule had become 
effective no later than May 1, 2023, but the EPA has also retained in 
the regulations the full-season emissions budgets for the 2023 control 
period that were established in the Revised CSAPR Update rulemaking. 
The EPA has added a provision to the regulations indicating that the 
emissions budgets promulgated in the Revised CSAPR Update will 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 will 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 will 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 previous and revised 
emissions budgets. (For example, if the final rule becomes effective on 
the eleventh day of the 153-day 2023 control period, the blended 
emissions budget will equal the sum of 10/153 times the previous 
emissions budget plus 143/153 times the revised emissions budget, 
rounded to the nearest allowance.) Blended variability limits for the 
2023 control period will be computed by first determining for each 
state the percentage by which the state's reported heat input for the 
full 2023 ozone season exceeds the heat input used to compute the 
state's full-season 2023 emissions budget under this rule and then 
multiplying the higher of this percentage or 21 percent by the state's 
prorated emissions budget and rounding to the nearest allowance,

[[Page 36812]]

yielding blended assurance levels that equal a minimum of 121 percent 
of the blended emissions budgets. Unit-level allocations will be 
determined by applying the allocation procedure described in section 
VI.B.9 to the blended budgets. Again, all calculations required to 
determine the prorated emissions budgets, the minimum 21 percent 
variability limits, and the unit-level allocations for the 2023 control 
period will be carried out as soon as possible after the EPA learns the 
effective date of this rule. The unit-level allocations for both the 
2023 and 2024 control periods will be recorded in facilities' 
compliance accounts approximately 30 days after the final rule's 
effective date, as discussed in section VI.B.9.b of this document.
    In the case of the states (and Indian country within the states' 
borders) whose sources currently participate in the Group 2 trading 
program--Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Texas, and 
Wisconsin--the sources will begin to participate in the Group 3 trading 
program as of May 1, 2023, regardless of the rule's effective date, as 
discussed in section VI.B.2 of this document, subject to prorating 
procedures designed to ensure that the transition from the Group 2 
trading program to the Group 3 trading program will not substantively 
affect the sources' requirements prior to the rule's effective date. 
The prorating procedures for these states 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 has added 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 program regulations, which are being 
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 rule's effective date, and second, the 
emissions budgets for the 2023 control period established for the 
states in this rulemaking, which are being 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 
rule's effective date. The procedures and timing for determining 
blended emissions budgets, variability limits and assurance levels, and 
unit-level allowance allocations, as well as the timing for the 
recordation of unit-level allocations, are the same as for the states 
currently in the Group 3 trading program.
    Beginning administrative implementation of the Group 3 trading 
program starting on May 1, 2023, for sources currently in the Group 2 
trading program imposes no new or different requirements on these 
sources. 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 is how the EPA handled the 
earlier transition of twelve states from the Group 2 to the Group 3 
trading program in the Revised CSAPR Update, which was accomplished 
successfully and without incident. See 86 FR 23133-34. This approach 
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 the 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 the 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 will 
implement the revised Group 3 trading program for the 2023 control 
period in a uniform manner for the entire control period. Thus, 
emissions will 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 will 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 will 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 in the three states that do not 
currently participate in the Group 2 trading program or the Group 3 
trading program, the 2023 control period will begin on the effective 
date of the rule, and because the effective date of the rule is 
expected to fall after May 1, 2023, the 2023 control period for the 
sources in these states will be shorter than the 153-day length of the 
2023 control period for the sources in the remaining states. However, 
the EPA similarly will implement the revised Group 3 trading program 
for the sources in these states in a uniform manner for the entire 
shorter control period.

[[Page 36813]]

    The prorating provisions are being finalized as proposed. The EPA 
received no comments on the portion of the proposal discussing these 
provisions.
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 percent 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 the EPA established the Group 3 trading program and 
transitioned approximately 55 percent 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 provide for 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 percent 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 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. The 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, 938 F.3d at 321.
    Under this final rule, applying the same balancing principle as in 
the CSAPR Update and the Revised CSAPR Update, the EPA will 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 transitioning over 80 percent 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 rule the EPA is applying a conversion procedure 
similar to the procedure followed in the CSAPR Update. Under the 
conversion procedure in this rule, the EPA has not set a predetermined 
conversion ratio in the regulations (as was done in the Revised CSAPR 
Update) but instead has established provisions identifying the target 
amount of new Group 3 allowances that will be created and defining the 
types of accounts whose holdings of Group 2 allowances will be 
converted to Group 3 allowances (as was done in the CSAPR Update). The 
conversion date will be carried out by September 18, 2023, which is 
expected to be approximately 2 months after the compliance deadline for 
the 2022 control period under the Group 2 trading program and 
approximately ten months before the compliance deadline for the 2023 
control period under the Group 3 trading program. The actual conversion 
ratio will be determined as of the conversion date and will 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.
    With respect to the numerator of the conversion ratio--that is, the 
total amount of Group 2 allowances being converted--the EPA has defined 
the types of accounts included in the conversion to include all 
accounts except the facility accounts of sources in states that will 
remain in the Group 2 trading program, consistent with the approach 
taken in the CSAPR Update.\368\ Thus, the accounts whose holdings of 
Group 2 allowances will be converted to Group 3 allowances will 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 will 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.
---------------------------------------------------------------------------

    \368\ The states whose sources will continue to participate in 
the Group 2 trading program for the 2023 control period will be 
Iowa, Kansas, and Tennessee.
---------------------------------------------------------------------------

    With respect to the denominator of the conversion ratio--that is, 
the target amount of Group 3 allowances that will be created in the 
conversion process--the EPA has followed the same approach for setting 
the target amount 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 in this rule will be 
computed as the sum of the minimum 21 percent variability limits for 
the 2024 control period \369\ established for the ten states being 
added to the Group 3 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 state emissions budgets and 
variability limits, the full-season target amount for the conversion 
would be 23,094 Group 3 allowances. The quantity of banked Group 2 
allowances currently held in accounts other than the facility accounts 
of sources in Iowa, Kansas, and Tennessee exceeding the quantity of 
allowances likely to be needed for 2022 compliance is approximately 
149,386 allowances. Thus, if the quantities of banked Group 2 
allowances held in the accounts being included in the conversion do not 
change between now and the conversion date, and if there was no 
prorating adjustment, the conversion ratio would be approximately 6.5-
to-1, meaning that one Group 3 allowance would be created for every 6.5 
Group 2 allowances deducted in the conversion process.\370\
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    \369\ 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 basing the bank target amount on the sum of the 
states' 2024 variability limits rather than the 2023 variability 
limits.
    \370\ By comparison, the analogous conversion ratio under the 
Revised CSAPR Update was 8-to-1.
---------------------------------------------------------------------------

    As noted in section VI.B.12.a of this document, the EPA expects 
that the effective date of this rule will occur after

[[Page 36814]]

the start of the 2023 ozone season, and prorating provisions are being 
promulgated in this rule 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) will take effect only after the 
rule's effective date. Consistent with these other procedures, the EPA 
will 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 23,094 allowances would be prorated to an initial 
bank target amount of 21,585 allowances.\371\ The EPA notes that 
prorating the bank amount in this manner will not reduce sources' 
compliance flexibility for the 2023 ozone season, because the amounts 
of Group 3 allowances that sources will receive for the portion of the 
2023 ozone season before the rule's effective date will be based on the 
trading program budgets for the 2023 control period that were in effect 
before this rulemaking. These trading program budgets exceed the 
sources' collective 2022 emissions by approximately 29,789 tons, 
indicating potentially surplus allowances roughly 1.3 times the full-
season bank conversion target amount of 23,094 allowances. Thus, 
although the prorating procedure will 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 will be more 
than offset by the quantities of Group 3 allowances that will be 
allocated in excess of sources' recent historical emissions levels for 
the portion of the ozone season before the final rule's effective date.
---------------------------------------------------------------------------

    \371\ 23,094 x (153-10) / 153 = 21,585.
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    As in the CSAPR Update and the Revised CSAPR Update, the EPA's 
overall objective in establishing the target amount for the allowance 
conversion is to achieve a total target amount for the bank at a level 
high enough to accommodate year-to-year 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. The EPA believes that a well-established 
trading program should be able to function with an allowance bank lower 
than the full amount of the covered states' variability limits, as 
discussed in section VI.B.6 of this document with respect to the bank 
recalibration process that will begin with the 2024 control period. 
However, the 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 will 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 established 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 will 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, 
the 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 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 will be removed from 
the program in the bank recalibration process that will be implemented 
starting with the 2024 control period and therefore will not weaken 
sources' incentives to control emissions on a permanent basis.
    The rule's provisions relating to the creation of an incremental 
Group 3 allowance bank are being finalized as proposed. Comments on the 
creation of the incremental allowance bank are discussed in section 5 
of the RTC.
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, the EPA is recalling 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 states and areas of Indian country 
transitioning to the Group 3 trading program and recorded in the 
sources' compliance accounts. The recall provisions 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 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 allow Group 2 
allowances of earlier vintages to be surrendered to achieve compliance. 
Like the similar recall provisions finalized in the Revised CSAPR 
Update, the 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

[[Page 36815]]

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 is determining that, 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 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 doing through the recall provisions.
    In this rule, the EPA is implementing 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 
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 are 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 later in this section. However, an 
exception is 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 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 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.\372\
---------------------------------------------------------------------------

    \372\ The EPA is currently unaware of any source that would need 
to use this flexibility but has included the option in the rule 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 will 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.\373\ 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.
---------------------------------------------------------------------------

    \373\ The first control period for the Group 2 trading program 
was in 2017.
---------------------------------------------------------------------------

    Owners and operators subject to the surrender requirements can 
choose from two possible deadlines for meeting the requirements. The 
optional first deadline will be 15 days after the effective date of 
this rule.\374\ As soon as practicable or after this date, the EPA will 
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 will 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 will first deduct allowances allocated for that 
control period and then will 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 will be met and also ensures that any Group 2 allowances 
left in the source's compliance account after completion of all 
required deductions will 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 will first deduct 
allowances that were initially recorded in that account, in the order 
of recordation, and will then deduct allowances that were transferred 
into that account after having been initially recorded in some other 
account, in the order of recordation.
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    \374\ As discussed later in this section and in section 
VI.B.9.b, the EPA has conditioned recordation of any allocations of 
Group 3 allowances in a source's compliance account on the source's 
prior compliance with the recall requirements for Group 2 
allowances. The purpose of providing an optional first deadline for 
the recall provisions 15 days after a final rule's effective is to 
ensure that sources have an early opportunity to comply with the 
recall provisions to be eligible to have allocations of Group 3 
allowances recorded in their accounts 30 days after the final rule's 
effective date. Because the vast majority of sources subject to the 
recall provisions already hold sufficient Group 2 allowances to 
comply with the recall provisions, the EPA anticipates that the 
sources will easily be able to comply with the optional first recall 
deadline.
---------------------------------------------------------------------------

    Following the first attempt to deduct Group 2 allowances to address 
Group 3 sources' surrender requirements, the

[[Page 36816]]

EPA will 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 will 
be sent to the email addresses most recently provided to the EPA for 
the recipients and will include information on how to contact the EPA 
with any questions. The EPA has provided that no allocations of Group 3 
allowances will 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 this rule will 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 
will 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 will 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 previously) as soon as practicable on or after 
September 15, 2023. The order in which Group 2 allowances are deducted 
will be the same as described previously 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 from a specified general account) is unsuccessful for a 
given source, 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 will 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 30, 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.\375\ 
Before making any deduction under this provision, the EPA will send a 
notification to the authorized account representative for the account 
in which the allowance is held and will provide an opportunity for 
submission of objections concerning the data upon which the EPA is 
relying. In EPA's view, this provision does not unduly interfere with 
the legitimate expectations of participants in the allowance markets 
because the provision will 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 30, 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 30, 2022, all market 
participants 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.\376\
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    \375\ The provision under which the EPA will not deduct Group 2 
allowances transferred to unrelated parties before April 30, 2022 
from the transferees' accounts does 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.
    \376\ 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.
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    The final revised regulations provide that failure of a source's 
owners and operators to comply with the surrender requirements will 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 are required to surrender under the recall provisions, the EPA 
has prepared a list of the sources in the 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 April 30, 2022, 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 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 will 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 recall provisions have been finalized without change from the 
proposal. The EPA received no comments on the proposed provisions.
13. Conforming Revisions to Regulations for Other CSAPR Trading 
Programs
    As noted in section VI.B.1.a of this document, 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.\377\ In this 
rulemaking, in addition to the revisions to the Group 3 trading 
program, the EPA is finalizing a set of conforming revisions that 
concern how various areas of Indian country are

[[Page 36817]]

treated for purposes of the allowance allocation provisions of the 
regulations for all the CSAPR trading programs.\378\
---------------------------------------------------------------------------

    \377\ The regulations for the Group 3 Trading Program are at 40 
CFR part 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.
    \378\ Additional conforming revisions concerning the schedules 
for the EPA to record allowance allocations in source's compliance 
accounts and for states to submit state-determined allowance 
allocations to the EPA for subsequent recordation were finalized in 
an earlier final rule in this docket. See 87 FR 52473 (August 26, 
2022).
---------------------------------------------------------------------------

    As discussed in section VI.B.9.a of this document, 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 revising 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 
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 VI.B.9.a of this 
document for the Group 3 trading program, the EPA is revising 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 are affected are identified in section IX.D 
of this document. The EPA is unaware of any currently operating units 
that would be affected by this revision to the regulations for the 
other CSAPR trading programs.
    The conforming revisions to the regulations for the other CSAPR 
trading programs concerning Indian country are being finalized as 
proposed with no changes. The EPA received no comments on this portion 
of the proposal.

C. Regulatory Requirements for Stationary Industrial Sources

    The EPA is finalizing FIPs with requirements for certain non-EGU 
industry sources for 20 of the states covered in this final rule. See 
section II.B of this document for the list of states. The FIPs include 
new emissions limitations for units in nine non-EGU industries that the 
EPA finds (as discussed in sections IV and V of this final rule) are 
significantly contributing to nonattainment or interfering with 
maintenance in other states. The emissions control requirements of 
these FIPs for non-EGU sources apply only during the ozone season (May 
through September) each year, beginning in 2026.
    To achieve the necessary non-EGU emissions reductions for these 20 
states, the EPA is finalizing the proposed emissions limitations with 
some adjustments as a result of information received during the public 
comment period. The final emissions limits apply to the most impactful 
types of units in the relevant industries and are achievable with the 
control technologies identified in this preamble and further discussed 
in the Final Non-EGU Sectors TSD. The non-EGU regulatory requirements 
unique to each industry that EPA is finalizing after considering public 
comments are discussed in sections VI.C.1 through VI.C.6 of this 
document.
    These final FIP requirements apply to both new and existing 
emissions units. The non-EGU emissions limits and compliance 
requirements will apply in all 20 states (and, as discussed in section 
III.C.2 of this document, 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 is 
consistent with the approach that the EPA proposed, and the EPA did not 
receive any comments specifically objecting to our proposal to regulate 
new units. This approach will ensure that all new sources constructed 
in any of the 20 states will be subject to the same good neighbor 
requirements that apply to existing units under this final rule. This 
will also avoid creating incentives to move production from an existing 
non-EGU source to a new non-EGU source of the same type but lacking the 
relevant emissions control requirements either within a linked state or 
in another linked state.
    Comment: The EPA received several comments regarding the proposed 
approach of establishing unit-specific emissions limitations for non-
EGUs instead of an emissions trading program. Some commenters suggested 
that a trading program for non-EGUs could provide for operational 
flexibility and that EPA should allow sources to work with regulatory 
authorities to develop a trading program. Other commenters generally 
supported EPA's proposed approach and the decision to not include non-
EGUs in an emissions trading program, because the EPA would not need to 
require sources to unnecessarily install CEMS. Commenters from several 
states and industry groups generally supported other monitoring options 
over CEMS, such as parametric monitoring, performance testing, and 
predictive emissions monitoring systems (PEMS). Additional commenters 
voiced concern with the expense and burden of continuous parametric 
monitoring and semi-annual performance tests. Specifically, commenters 
explained that semi-annual testing should not be required when the 
emissions limits only apply during the ozone season. Commenters also 
noted that many non-EGU boilers have recently been relieved from 
meeting the CEMS requirements under the 1998 NOX SIP Call 
and that implementing CEMS on many of the non-EGU sources would be 
difficult and unnecessary.
    Response: The EPA is finalizing a unit-specific approach with rate-
based emissions limitations 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. In 
response to public comments, the EPA has adjusted these requirements as 
necessary to ensure that the emissions control requirements are 
achievable while ensuring that the FIPs achieve the necessary emissions 
reductions from the covered units to eliminate significant contribution 
to nonattainment and interference with maintenance as discussed in 
section V of this document. The EPA has concluded that a unit-specific 
approach is more appropriate for non-EGUs at this time than 
implementing a trading program and requiring all units to implement 
rigorous part 75 monitoring and reporting requirements. As explained in 
the proposal, to be considered for a trading program, non-EGU sources 
would have to comply with requirements for monitoring and reporting of 
hourly mass emissions in accordance with 40 CFR part 75 as we have 
required for all previous 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. Consistent and accurate measurement of emissions is 
necessary to ensure that 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

[[Page 36818]]

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. Many industry and state commenters 
provided information confirming that many non-EGU units subject to this 
rulemaking do not currently utilize CEMS and specifically requested 
that EPA avoid requiring CEMS for all non-EGU industries. The EPA 
generally agrees that CEMS is not necessary for all non-EGU industries 
under the approach of this final rule and is finalizing other 
continuous monitoring, recordkeeping, and reporting requirements, as 
appropriate, that are specific to each non-EGU industry. The EPA has 
determined that establishing unit-specific emissions limitations for 
non-EGUs is a preferable approach in part because it avoids the 
rigorous monitoring requirements that would be applied to non-EGUs for 
the first time under a trading program.
    Furthermore, to address commenters' concerns regarding non-EGU 
requirements for performance testing on a semi-annual basis, the EPA 
has also reduced the frequency of all required performance testing for 
non-EGU sources to once per calendar year. As commenters correctly 
pointed out, the emissions limits in these final FIPs only apply during 
the ozone season and testing once per calendar year should be 
sufficient to confirm the accuracy of the parameters being monitored to 
demonstrate continuous compliance during the ozone season. The EPA also 
agrees with commenters that the annual testing requirements need not 
occur during the ozone season.
    In addition, the EPA is modifying the applicability criteria and 
other regulatory requirements in response to public comments to provide 
certain compliance flexibilities for non-EGU industries where 
appropriate. As discussed further in section V.C.1 of this document, 
the EPA is modifying the requirements for Pipeline Transportation of 
Natural Gas by finalizing an exemption for emergency engines and 
allowing any owner or operator of an affected unit to propose a 
``Facility-Wide Averaging Plan'' that would, if approved by EPA, 
provide an alternative means for compliance with the emissions limits 
in this final rule. Further, as discussed in section VI.C.5 of this 
document, the EPA is finalizing a low-use exemption for non-EGU boilers 
that operates less than 10 percent per year on an hourly basis, based 
on the three most recent years of use and no more than 20 percent in 
any one of the three years. These final rule provisions require 
controls on the most impactful non-EGU industrial sources while 
providing the flexibility needed to accommodate unique circumstances on 
a case-by-case basis.
    Comment: Commenters from several non-EGU industries and states 
raised general concerns regarding the ability for all sources to comply 
with the proposed emissions limits. Some commenters suggested that the 
EPA allow for case-by-case limits where necessary, similar to case-by-
case RACT determinations. Specifically, commenters operating boilers, 
furnaces, and MWCs provided general explanations of how some units 
might not be able to meet the proposed emissions limits and requested 
that EPA provide for compliance flexibility where a source can 
demonstrate technical and economical infeasibility.
    Response: As explained more in sections VI.C.1 through VI.C.6, the 
EPA has made several adjustments to the proposed applicability 
criteria, emissions limits, and compliance requirements in response to 
public comments and to reduce the costs of compliance with the final 
rule. For Pipeline Transportation and Natural Gas, the EPA is 
finalizing emissions averaging provisions and exemptions for emergency 
engines to allow facilities to avoid installing controls on units with 
lower actual emissions where the installation of controls would be less 
cost effective compared to higher-emitting units. For Cement and 
Concrete Product Manufacturing, the EPA has removed the daily source 
cap that would have resulted in an artificially restrictive 
NOX emissions limit for affected cement kilns that have 
operated at lower levels due to the COVID-19 pandemic. For Iron and 
Steel and Ferroalloy Manufacturing, the EPA is finalizing a ``test-and-
set'' requirement for reheat furnaces that will require the 
installation of low-NOX burners or equivalent technology. 
The EPA has addressed the economic concerns raised by commenters 
regarding installation of controls at Iron and Steel facilities by not 
finalizing the other ten proposed emissions limits that were intended 
to require the installation of SCR at these facilities. For Glass and 
Glass Product Manufacturing, the EPA is finalizing alternative 
standards that apply during startup, shutdown, and idling conditions. 
For boilers in Basic Chemical Manufacturing, Petroleum and Coal 
Products Manufacturing, Pulp, Paper, and Paperboard Mills, Metal Ore 
Mining, and the Iron and Steel Industry, the EPA is finalizing a low-
use exemption to eliminate the need to install controls on boilers that 
would have resulted in relatively small reductions in emissions. 
Finally, the EPA has modified the monitoring and recordkeeping 
requirements for all non-EGU industries where possible to reduce the 
testing frequency to once a year and to provide for alternative 
monitoring protocols where appropriate, which should further reduce the 
costs of compliance on non-EGU sources. With these modifications to the 
final rule in response to comments, the non-EGU sources subject to this 
rule should be able to meet the applicable control requirements 
established in this final rule.
    The EPA also recognizes, however, that there may be unique 
circumstances the Agency cannot anticipate that would, for a particular 
source, render the final emissions control requirements technically 
impossible or impossible without extreme economic hardship. To address 
these limited circumstances, the EPA is finalizing a provision that 
allows a source to request EPA approval of a case-by-case emissions 
limit based on a showing that an emissions unit cannot meet the 
applicable standard due to technical impossibility or extreme economic 
hardship. The EPA has modeled the case-by-case emissions limit 
mechanism on case-by-case RACT requirements and certain facility-
specific emissions limits under 40 CFR part 60 identified by 
commenters.\379\ The owner or operator of a source seeking a case-by-
case emissions limit must submit a request meeting specific 
requirements to the EPA by August 5, 2024, one year after the effective 
date of this final rule. The applicable emissions limits established in 
this final rule remain in effect until the EPA approves a source's 
request for a case-by-case emissions limit. Given the May 1, 2026 
compliance date that generally applies to all affected units in the 
non-EGU industries covered by this final rule, we encourage owners and 
operators of affected units who believe they must seek case-by-case 
emissions limits to submit their requests to the EPA before the one-
year deadline for such requests, if possible, to ensure adequate time 
for EPA review and to install the necessary controls.
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    \379\ For examples of case-by-case RACT provisions and source 
specific limits for boilers in subpart Db of the EPA's NSPS, see 40 
CFR 60.44b(f); Regulations of Connecticut State Agencies section 
22a-174-22e; Code of Maryland Regulations section 26.11.09.08(B)(3); 
and Code of Maine Rules section 096-138-3, subsection (I).
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    For a source requesting a case-by-case limit due to technical 
impossibility, the final rule requires that the request include 
emissions data obtained through CEMS or stack tests, an analysis

[[Page 36819]]

of all available control technologies based on an engineering 
assessment by a professional engineer or data from a representative 
sample of similar sources, and a recommendation concerning the most 
stringent emissions limit the source can technically achieve.
    For a source requesting a case-by-case limit on the basis of 
extreme economic hardship, the final rule requires that the request 
include at least three vendor estimates from three separate vendors 
that do not have a corporate or business-affiliation with the source of 
the costs of installing the control technology necessary to meet the 
applicable emissions limit and other information that demonstrates, to 
the satisfaction of the Administrator, that the cost of compliance with 
the applicable emissions limit for that particular source would present 
an extreme economic hardship relative to the costs borne by other 
comparable sources in the industry under this rule. In evaluating a 
source's request for a case-by-case limit due to extreme economic 
hardship, the EPA will consider the emissions reductions and costs 
identified in this final rulemaking (and related support documents) for 
other sources in the relevant industry and whether the costs of 
compliance for the source seeking the case-by-case limit would 
significantly exceed the highest representative end of the range of 
estimated cost-per-ton figures identified for any source in the 
relevant industry as discussed in section V of this document.
    As discussed in section VI.A of this document, in Wisconsin the 
court held that some deviation from the CAA's 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.\380\ Given these directives, the EPA cannot allow 
a covered source to avoid complying with the emissions limits 
established in this final rule unless the source can demonstrate that 
compliance with the limit would either be impossible as a technical 
matter or result in an extreme economic hardship--i.e., exceed the high 
end of the cost-effectiveness estimates that informed the EPA's Step 3 
determination of significant contribution, as discussed in section V of 
this document. The criteria that must be met to qualify for a case-by-
case limit are designed to meet this statutory mandate.
---------------------------------------------------------------------------

    \380\ Wisconsin, 938 F.3d 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'').
---------------------------------------------------------------------------

    Comment: Several commenters raised concerns about the EPA's 
differing applicability criteria for the various non-EGU industries. 
Specifically, the commenters questioned why EPA set applicability 
criteria for engines in Pipeline Transportation of Natural Gas and non-
EGU boilers based on design capacity instead of potential to emit 
(PTE). Commenters also requested that the EPA allow each non-EGU 
category to rely on operating permits or other federally enforceable 
instruments to avoid being subject to the rule, such as limits to the 
PTE or limits on fuels used.
    Response: The 100 tpy PTE threshold and comparable design capacity 
thresholds of 1,000 horsepower (hp) for engines and 100 mmBtu/hr for 
boilers are appropriate to ensure that the final rule reduces emissions 
from the most impactful units. The EPA finds the control technologies 
assumed to be installed to meet the final emissions limits would not be 
as readily available or cost effective for emissions units with PTE or 
design capacities lower than the applicability thresholds in this final 
rule.
    With regard to the selection of design capacity thresholds for 
boilers and engines, the EPA finds that most RACT requirements and 
other standards reviewed by the EPA establish applicability criteria 
for engines and boilers based on design capacity rather than PTE. We 
further explain our basis for establishing applicability thresholds 
based on design capacity for these two source categories in sections 
VI.C.1. and VI.C.5. For consistency with preexisting requirements for 
engines and boilers and to capture the sizes of units identified in 
Step 3 of our analysis, the EPA selected design capacities of 1,000 hp 
for engines and 100 mmBtu/hr for boilers. The EPA recognizes that these 
applicability thresholds captured more units than the EPA intended, 
particularly some low-use units. Therefore, as explained in sections 
VI.C.1 and VI.C.5., the EPA is establishing exemptions for low-use 
boilers and emergency engines, as well as new emissions averaging 
provisions for engines, to ensure that this final rule focuses on 
larger, more impactful units.
    The EPA also agrees with commenters that the applicability criteria 
should allow for sources to rely on enforceable requirements that limit 
a source's PTE and is finalizing a regulatory definition of PTE that is 
generally consistent with the definitions of that term in the EPA's 
title V and NSR permit programs. See, e.g., 40 CFR 51.165(a)(1)(iii), 
70.2. In constructing the list of potential sources subject to the 
final rule, the EPA relied on available information to identify the PTE 
of the emissions units in the various non-EGU industries that are 
captured by the applicability criteria. See Memo to Docket titled 
Summary of Final Rule Applicability Criteria and Emissions Limits for 
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the 
Final Emissions Limits, and Estimated Emissions Units, Emissions 
Reductions, and Costs. Thus, the EPA's Step 3 analysis takes into 
account available information about currently enforceable emissions 
limits and physical and operational limitations identified in existing 
permits. The EPA finds it necessary to define PTE consistent with its 
use in the title V and NSR permit programs to ensure that the 
requirements of the final FIPs apply to the most impactful units 
identified in Step 3 of our analysis. However, to ensure that these 
FIPs achieve the emissions reductions necessary to eliminate 
significant contribution or interference with maintenance as described 
in this final rule, the applicability criteria for the Cement and 
Concrete Manufacturing, Iron and Steel and Ferroalloy Manufacturing, 
and Glass and Glass Product Manufacturing industries take into account 
only those enforceable PTE limits in effect as of the effective date of 
this final rule. Thus, any emissions unit in these three industries 
that has a PTE equal to or greater than 100 tons per year and thus 
meets the definition of an ``affected unit'' as of August 4, 2023, will 
remain subject to the applicable FIPs, without regard to any PTE limit 
that the emissions unit may subsequently become subject to. Each 
affected unit in these three industries must submit an initial 
notification of applicability to the EPA by December 4, 2023, that 
identifies its PTE as of the effective date of this final rule. 
Additionally, any owner or operator of an existing emissions unit that 
is not an affected unit as of August 4, 2023, but subsequently meets 
the applicability criteria (e.g., due to a change in fuel use that 
increases the unit's PTE) will become an affected unit subject to the 
applicable requirements of this final rule at that time.
    Comment: In responding to the EPA's request for comment on whether 
some non-EGU units would need to run controls required by the final FIP 
year-round, one commenter anticipated that control equipment would be 
operated as necessary to achieve applicable emissions limits, but that 
operational

[[Page 36820]]

flexibility, cost considerations and equipment longevity would warrant 
operation of certain control equipment on a schedule such that the 
equipment would not be used when unnecessary to meet emissions limits 
and/or outside of ozone season (i.e., during winter months). The 
commenter further explained that flexibility in the operation of 
certain control equipment when unnecessary to meet emissions limits 
will allow for routine maintenance and repairs without requiring 
variances or similar exemptions from continuous operation requirements.
    Response: Based on the feedback received during the public comment 
period, the EPA is finalizing requirements for non-EGU sources that 
will apply only during the ozone season, which runs annually from May 
to September. As discussed in the proposed rule, 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. In addition, the EPA did 
not receive any information during the public comment period suggesting 
that sources would have to run the necessary controls year-round due to 
the nature of those controls. We note, however, that certain emissions-
control technologies, such as combustion controls that are integrated 
into the unit itself, would likely function to reduce NOX 
emissions year-round as a practical engineering matter.
    Comment: Regarding electronic reporting through the Compliance and 
Emissions Data Reporting Interface (CEDRI), one commenter requested 
that CEDRI reporting requirements be consolidated in one location 
rather than repeated in each section. Another commenter requested that 
EPA include electronic reporting requirements for MWCs and specifically 
require that MWCs report CEMS data to CEDRI. Another commenter 
requested that EPA allow for extensions of time for electronic reports 
due to technical glitches.
    Response: To increase the ease and efficiency of data submittal and 
data accessibility, the EPA is finalizing, as proposed, a requirement 
that owners and operators of non-EGU sources subject to the final FIPs, 
including MWCs, submit electronic copies of required initial 
notifications of applicability, performance test reports, performance 
evaluation reports, quarterly and semi-annual reports, and excess 
emissions reports through EPA's Central Data Exchange (CDX) using the 
CEDRI. The final rule requires that performance test results collected 
using test methods that are supported by the EPA's Electronic Reporting 
Tool (ERT) as listed on the ERT website \381\ 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 finalizing a requirement 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 a requirement that other 
performance evaluation results be submitted in PDF using the attachment 
module of the ERT. The final rule also requires that initial 
notifications of applicability, annual compliance reports, and excess 
emissions reports be submitted in PDF uploaded in CEDRI.
---------------------------------------------------------------------------

    \381\ The ERT website is located at https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    Furthermore, the EPA is finalizing, as proposed, provisions that 
allow owners and operators to seek extensions of time to submit 
electronic reports due to circumstances beyond the control of the owner 
or operator (e.g., due to a possible outage in CDX or CEDRI or a force 
majeure event) in the time just prior to a report's due date, as well 
as provisions specifying how to submit such a claim. Public commenters 
supported these proposed provisions.
    The EPA agrees with commenters that the CEDRI reporting 
requirements could be centralized and has moved the CEDRI reporting 
requirements to 40 CFR 52.40.
1. Pipeline Transportation of Natural Gas
Applicability
    The EPA is finalizing 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 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 100 
tpy PTE threshold used in the Screening Assessment of Potential 
Emissions Reductions, Air Quality Impacts, and Costs from Non-EGU 
Emissions Units for 2026, as described in section V.B of this document.
    The EPA is also modifying certain provisions in response to public 
comments to provide compliance flexibilities for the Pipeline 
Transportation of Natural Gas industry sector in order to focus 
emissions reduction efforts on the highest emitting units. 
Specifically, the EPA is finalizing an exemption for emergency engines, 
and establishing provisions that allow any owner or operator of an 
affected unit to propose a Facility-Wide Averaging Plan that would, if 
approved by EPA, provide an alternative means for compliance with the 
emissions limits in this final rule.
    For purposes of this rule, the EPA is clarifying and narrowing the 
definition of ``pipeline transportation of natural gas'' to mean the 
transport or storage of natural gas prior to delivery to a local 
distribution company custody transfer station or to a final end-user 
(if there is no local distribution company custody transfer station). 
The revised definition of this term in Sec.  52.41(a) is consistent 
with the EPA's regulatory definition of ``natural gas transmission and 
storage segment'' in 40 CFR 60.5430(a) (subpart OOOOa, Standards of 
Performance for Crude Oil and Natural Gas Facilities for Which 
Construction, Modification, or Reconstruction Commenced After September 
18, 2015).
    The EPA is also adding definitions of the terms ``local 
distribution company'' and ``local distribution company custody 
transfer station'' that are consistent with the definitions found in 40 
CFR 98.400 (subpart NN, Suppliers of Natural Gas and Natural Gas 
Liquids) and 40 CFR 60.5430(a) (subpart OOOOa, Standards of Performance 
for Crude Oil and Natural Gas Facilities for Which Construction, 
Modification, or Reconstruction Commenced After September 18, 2015), 
respectively.
    Comment: Several commenters asked EPA to exclude emergency engines 
in the final rule and one commenter recommended that the EPA revise the 
definition of affected unit to specifically exempt emergency engines. 
Commenters stated that doing so would not only be consistent with other 
regulations applicable to stationary SI engines, but it would also be 
more consistent with EPA's applicability analysis, which assumes 
stationary SI engines will operate for 7,000 hours a year, something 
emergency engines are prohibited from doing by Federal regulation. 
Commenters also stated that emergency generators are currently exempt 
from requirements applicable to non-emergency RICE covered by both

[[Page 36821]]

the relevant NSPS rule (subpart JJJJ), as well as the relevant NESHAP 
rule (subpart ZZZZ), and that although the NSPS and NESHAP standards 
EPA has adopted for emergency RICE do not limit the amount of time they 
may run for emergency purposes, EPA has recognized in the past that 
states may assume a maximum of 500 hours of operation to estimate the 
``potential to emit'' in issuing air permits for emergency RICE. One 
commenter asserted that emergency engines operating under other 
standards currently only operate for emergencies or for a few hours at 
a time to periodically conduct regular maintenance, that their 
emissions are low, and that their contribution to the ozone transport 
issues EPA's proposal seeks to address is negligible. Another commenter 
stated that the EPA has traditionally exempted emergency engines in 
past standards because the EPA has typically found that the use of add-
on emissions controls cannot be justified due to the cost of the 
technology relative to the emissions reduction that would be obtained.
    Response: With respect to stationary SI emergency engines, the EPA 
has reviewed the information submitted by the commenters and has 
decided to exempt such engines from the requirements of the final rule. 
Exemption of emergency engines is generally consistent with the EPA's 
treatment of emergency engines in other CAA rulemakings. See, e.g., 40 
CFR 63.6585(f). The EPA expects that this change from the proposed rule 
addresses the concerns expressed by the commenters about the 
requirements for stationary emergency engines.
    The final rule defines emergency engines as engines that are 
stationary and operated to provide electrical power or mechanical work 
during an emergency situation. These engines are typically used only a 
few hours per year, and the costs of emissions control are not 
warranted when compared to the emissions reductions that would be 
achieved.
    In the final rule, emergency engines are subject to certain 
compliance requirements on a continuous basis. Continuous compliance 
requirements include operating limitations that apply during non-
emergency use but do not include emissions testing of emergency 
engines.
    Comment: Several commenters raised concerns about the EPA's 
proposal to establish applicability criteria for engines in Pipeline 
Transportation of Natural Gas based on design capacity rather than PTE. 
Other commenters asserted that the horsepower rating of an engine does 
not necessarily correspond to its annual emissions and that engines 
with a rated capacity of more than 1,000 hp in this industry sector may 
operate at low load and/or infrequently and be associated with limited 
NOX emissions. One commenter stated that most of the subject 
facilities in their state that have natural gas fired SI engines with a 
nameplate capacity rating of 1,000 hp or greater have annual 
NOX emissions less than 100 tpy, with nearly 25 percent of 
them less than 25 tpy. The commenter suggested that the 1,000 hp 
applicability threshold would result in overcontrol. According to one 
commenter, the EPA has overestimated the emissions rates and operating 
hours of engines with a rated capacity of more than 1,000 hp and thus 
underestimated the size of pipeline RICE that would be expected to emit 
more than 100 tpy of NOX annually. According to this 
commenter, only engines much larger than 1,000 hp are likely to emit at 
the level EPA deemed appropriate for regulation.
    Another commenter suggested that the EPA should use a 150 ton per 
year threshold that the commenter alleges was used in the Revised CSAPR 
Update rulemaking so that stationary SI engines are regulated on equal 
footing with EGUs and raise the 1,000 hp threshold to 2,000 hp, which 
according to the commenter would not sacrifice the emissions reductions 
to be achieved.
    Response: As explained in the proposal, the EPA found that most 
RACT requirements and other standards reviewed by the EPA establish 
applicability criteria for engines based on design capacity rather than 
PTE. For consistency with preexisting requirements for engines, the EPA 
selected a design capacity of 1,000 hp for engines to capture the sizes 
of units identified in Step 3 of our analysis. Based on the Non-EGU 
Screening Assessment memorandum, engines with a potential to emit of 
100 tpy or greater had the most significant potential for 
NOX emissions reductions. The EPA recognizes that the use of 
a 1,000 hp design capacity as part of the applicability criteria may 
capture low-use units and some units with emissions of less than 100 
tons per year. However, it is also not possible to guarantee without an 
effective emissions control program that all such units could not 
increase emissions in the future. As discussed in section V of this 
document, we continue to find that collectively engines with a design 
capacity of 1,000 hp or higher in the states and industries covered by 
this final rule emit substantial amounts of NOX that 
significantly contribute to downwind air quality problems.
    However, in response to concerns raised by commenters while 
continuing to ensure that this rule establishes an effective emissions 
control program for these units that is consistent with our Step 3 
determinations, the EPA is establishing a compliance alternative using 
facility-wide emissions averaging, which will allow facilities to 
prioritize emissions reductions from larger, higher-emitting units. (As 
previously discussed, we are also establishing an exemption for 
emergency engines, which also helps ensure that this final rule focuses 
on larger, more impactful units in this industry.) The facility-wide 
emissions averaging alternative is explained in the following 
paragraphs.
Emissions Limitations and Rationale
    In developing the emissions limits for the Pipeline Transportation 
of Natural Gas industry, the 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 (ppmv), 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 final FIP as well.
    Based on the available information for this industry, including 
applicable State and local air agency rules and active air permits 
issued to sources with similar engines, the EPA is finalizing the 
following emissions limits for stationary SI engines in the covered 
states. Beginning in the 2026 ozone season and in each ozone season 
thereafter, the following emissions limits apply, based on a 30-day 
rolling average emissions rate during the ozone season:

[[Page 36822]]



    Table VI.C-1--Summary of Final NOX Emissions Limits for Pipeline
                      Transportation of Natural Gas
------------------------------------------------------------------------
                                                           Final NOX
                 Engine type and fuel                   emissions limit
                                                           (g/hp-hr)
------------------------------------------------------------------------
Natural Gas Fired Four Stroke Rich Burn..............                1.0
Natural Gas Fired Four Stroke Lean Burn..............                1.5
Natural Gas Fired Two Stroke Lean Burn...............                3.0
------------------------------------------------------------------------

    The EPA anticipates that, in some cases, affected engines will need 
to install NOX controls to comply with the final emissions 
limits in Table VI.C-1. The emissions limits for four stroke rich burn 
engines, four stroke lean burn engines and two stroke lean burn engines 
are designed to be achievable by installing Non-Selective Catalytic 
Reduction (NSCR) on existing four stroke rich burn engines; installing 
SCR on existing four stroke lean burn engines; and retrofitting layer 
combustion on existing two stroke lean burn engines as identified in 
the Final Non-EGU Sectors TSD. Sources have the flexibility to install 
any other control technologies that enable the affected units to meet 
the applicable emissions limit on a continuous basis.
    The EPA is establishing provisions that allow any owner or operator 
of an affected unit in the Pipeline Transportation of Natural Gas 
Industry to propose a Facility-Wide Averaging Plan that would, if 
approved by EPA, provide an alternative means for compliance with the 
emissions limits in this final rule. These provisions will provide some 
flexibility to owners and operators of affected units to determine 
which engines to control and at what level, so long as the average 
emissions across all covered units, on a weighted basis, meet the 
applicable emissions limits for each engine type. This approach allows 
facilities to target the most cost-effective emissions reductions and 
to avoid installing controls on equipment that is infrequently 
operated.
    We provide a more detailed discussion of the basis for the final 
emissions limits and the anticipated control technologies to be 
installed in the Final Non-EGU Sectors TSD.
Four Stroke Rich Burn and Four Stroke Lean Burn Engines
    The EPA requested comment on whether a lower emissions limit is 
appropriate for four stroke rich burn engines 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. The EPA also requested 
comment on whether a lower or higher emissions limit is appropriate for 
four stroke lean burn engines.
    Comment: One commenter stated that the limits as proposed were not 
technically feasible in all circumstances. The commenter explained that 
its company has 150 four stroke rich burn engines in its fleet and that 
some of those engines cannot achieve the proposed 1.0 g/hp-hr limit 
even with both NSCR and layered combustion due to the vintage design of 
the individual cylinder geometry and the fact that most of these 
engines are not in production today, which limits availability of parts 
and retrofit technologies. The commenter asserted that 10 of its four 
stroke rich burn engines have all available controls on them and half 
of those still exceed the proposed limits. The commenter estimated that 
10 of its four stroke lean burn engines would require SCR to meet the 
1.5 g/hp-hr limit and that this control installation would require 
custom retrofit due to the age of these engines. Furthermore, the 
commenter stated that if current limits are not achievable in all 
circumstances, then lower limits are likewise impossible for four 
stroke rich burn engines and four stroke lean burn engines in even more 
circumstances. The commenter stated that the technical feasibility of 
installing controls on any single existing engine varies and depends, 
in part, on site-specific and engine-specific considerations such as 
space for the installation of the control, the availability of 
sufficient power, the emissions reductions required to meet the 
applicable standards, and the vintage, make, and model of a particular 
engine. Another commenter recommended tightening the proposed emissions 
standards for four stroke lean burn engines to an emissions limit 
similar to Colorado's limit of 1.2 g/hp-hr. A third commenter noted 
that the District of Columbia Department of Energy and Environment has 
NOX emissions limits for both rich- and lean burn engines 
burning natural gas at 0.7 g/hp-hr.
    Response: The EPA is finalizing the emissions limits for both four 
stroke rich burn engines and four stroke lean burn engines as proposed 
but also establishing alternative compliance provisions and criteria 
for establishing case-by-case alternative emissions limits in response 
to the concerns raised by commenters. NSCR can achieve NOX 
reductions of 90 to 99 percent, and engines in California, Colorado, 
Pennsylvania and Texas have achieved the emissions limits that the EPA 
had proposed. Based on this information and the emissions limits and 
NOX controls analysis developed by the OTC in a report 
entitled Technical Information Oil and Gas Sector Significant 
Stationary Sources of NOX Emissions (October 17, 2012), the EPA is 
finalizing a 1.0 g/hp-hr emissions limit for four stroke rich burn 
engines and a 1.5 g/hp-hr emissions limit for four stroke lean burn 
engines. The Final Non-EGU Sectors TSD provides a more detailed 
explanation of the basis for these emissions limits.
    To address the concerns raised by some commenters that not all 
engines may be able to achieve the emissions limits as proposed due to 
engine vintage and technical constraints, the final rule allows any 
owner or operator of an affected unit to request a Facility-Wide 
Averaging Plan that would, if approved by EPA, provide an alternative 
means for compliance with the emissions limits in the final rule. An 
approved Facility-Wide Averaging Plan would allow the owner or operator 
of the facility to identify the most cost-effective means for 
installing the necessary controls (i.e., by installing controls on the 
subset of engines that provide the greatest emissions reduction 
potential at lowest costs). In addition to the Facility-Wide Averaging 
Plan provisions, the final rule allows owners and operators to seek EPA 
approval of alternative emissions limits, on a case-by-case basis, 
where necessary due to technical impossibility or to avoid extreme 
economic hardship. The provisions governing case-by-case alternative 
limits are explained in more detail in section VI.C of this document.
Two Stroke Lean Burn Engines
    The EPA requested comment on whether a lower emissions limit would 
be achievable with layered combustion alone for the two stroke lean 
burn engines covered by this final rule. The

[[Page 36823]]

EPA also sought comment on whether these engines could install 
additional control technology at or below the marginal cost threshold 
to achieve a lower emissions rate.
    Comment: Commenters did not specifically address whether a lower 
emissions limit would be achievable with layered combustion alone at 
two stroke lean burn engines. However, one commenter stated that older 
two stroke lean burn engines generally would not be able to achieve the 
proposed NOX emissions limits. The commenter stated that 
conversion kits are available for several models that can reduce 
emissions but that such kits are not made for all models, especially 
older stationary engines. Commenters further stated that where 
conversion kits are not available, a company would likely have no 
choice but to replace the older four stroke or two stroke stationary 
engines, typically at a cost of $2 million to $4 million each.
    Two commenters stated that they are required by their state agency 
to have RACT, BACT, or BART controls, at minimum. Commenters stated 
that requiring additional controls at facilities already equipped with 
RACT, BACT or BART control technologies would not achieve the 
anticipated emissions reductions due to operational factors inherent in 
the preexisting and pre-controlled equipment and that the achievability 
of targeted control levels is highly dependent upon a number of 
variables at each facility.
    Another commenter suggested that the EPA set lower limits for two 
stroke lean burn engines similar to the OTC-recommended limits in the 
range of 1.5-2.0 g/hp-hr.
    Response: Information currently available to the EPA indicates that 
the amount of emissions reductions achievable with layered combustion 
controls 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 up to 80 percent to comply with a 3.0 g/hp-hr emissions 
limit. The EPA has found that engines in California, Colorado, 
Pennsylvania and Texas have achieved these emissions rates. Based on 
this information and the emissions limits and NOX controls 
analysis developed by the OTC in a report entitled Technical 
Information Oil and Gas Sector Significant Stationary Sources of NOX 
Emissions (October 17, 2012), the EPA is finalizing a 3.0 g/hp-hr 
emissions limit for two stroke lean burn engines. Although some 
affected units may be able to achieve a lower emissions rate, we find 
that a 3.0 g/hp-hr emissions limit generally reflects a level of 
control that is cost-effective for the majority of the affected units 
and sufficient to achieve the necessary emissions reductions. As 
explained in the proposed rule and expressed by public commenters, if 
the EPA were to establish an emissions limit lower than 3.0 g/hp-hr, 
some two stroke lean burn engines would not be able to meet the 
emissions limit with the installation of layered combustion control 
alone. In that case, the lower limit might require the installation of 
SCR, which the EPA did not find to be cost-effective for two stroke 
lean burn engines in its Step 3 analysis.\382\ The Final Non-EGU 
Sectors TSD provides a more detailed explanation of the basis for this 
emissions limit.
---------------------------------------------------------------------------

    \382\ 87 FR 20036, 20143 (noting that an emissions limit below 
3.0 g/hp-hr may require some two stroke lean burn engines to install 
additional controls beyond the EPA's cost threshold).
---------------------------------------------------------------------------

    In response to commenters' concerns about the difficulties involved 
in retrofitting or replacing older stationary engines to achieve the 
EPA's proposed emissions limit, the final rule allows any owner or 
operator of an affected unit to request a Facility-Wide Averaging Plan 
that would, if approved by EPA, provide an alternative means for 
compliance with the emissions limits in the final rule. In addition to 
the Facility-Wide Averaging Plan provisions, the final rule allows 
owners and operators to seek EPA approval of alternative emissions 
limits, on a case-by-case basis, where necessary due to technical 
impossibility or to avoid extreme economic hardship. However, in the 
context of older or ``vintage,'' high-emitting engines in this industry 
for which commenters claim emissions control technology retrofit is not 
feasible, the Agency anticipates taking into consideration the cost 
associated with alternative compliance strategies, such as replacement 
with new, far more efficient and less polluting engines, in evaluating 
claims of extreme economic hardship.
Facility-Wide Averaging Plan
    The EPA is finalizing regulatory text that provides for an 
emissions limit compliance alternative using facility-level emissions 
averaging. An approved Facility-Wide Averaging Plan will allow the 
owner or operator of the facility to average emissions across all 
participating units and thus to select the most cost-effective means 
for installing the necessary controls (i.e., by installing controls on 
the subset of engines that provide the greatest emissions reduction 
potential at lowest costs and avoiding installation of controls on 
equipment that is infrequently operated or otherwise less cost-
effective to control). So long as all of the emissions units covered by 
the Facility-Wide Averaging Plan collectively emit less than or equal 
to the total amount of NOX emissions (in tons per day) that 
would be emitted if each covered unit individually met the applicable 
NOX emissions limitations, the covered units will be in 
compliance with the final rule. Under this alternative compliance 
option, facilities have the flexibility to prioritize emissions 
reductions from larger, dirtier engines.
    Comment: Several commenters recommended that the EPA promulgate 
emissions averaging provisions, as it did in the 2004 NOX 
SIP Call Phase 2 rule (69 FR 21604), in which the EPA evaluated and 
supported reliance on emissions averaging for RICE in the Pipeline 
Transportation of Natural Gas industry sector. The commenter stated 
that the EPA's guidance to states on developing an appropriate SIP in 
response to the SIP Call provided companies the ``flexibility'' to use 
a number of control options, as long as the collective result achieved 
the required NOX reductions, and that many states built 
their revised SIPs around the emissions averaging approach addressed in 
this guidance document.\383\ One commenter recommended that the EPA 
allow intra-state emissions averaging across all pipeline RICE owned or 
operated by the same company. Another commenter asserted that units of 
certain vintages and units from certain manufacturers will not be able 
to meet the emissions rate limits the EPA had proposed. The commenter 
claimed that, absent a system based on source-specific emissions 
limits, emissions averaging is one of the only practical mechanisms for 
addressing these challenges.
---------------------------------------------------------------------------

    \383\ The commenter refers to an August 22, 2002 memorandum from 
Lydia N. Wegman, Director, EPA, Air Quality Strategies and Standards 
Division to EPA Air Division Directors, entitled ``State 
Implementation Plan (SIP) Call for Reducing Nitrogen Oxides 
(NOX)--Stationary Reciprocating Internal Combustion 
Engines.''
---------------------------------------------------------------------------

    One commenter stated that it had evaluated the cost of controls for 
engines in its fleet and that the variety in cost-per-ton for each 
potential project counsels for a more flexible approach, like an 
averaging program. Another commenter advocated for an emissions 
averaging plan that would allow an engine-by-engine showing of economic 
infeasibility to ensure a cost-effective application of the emissions 
standards, a reduced impact on natural gas capacity, and a means for 
addressing the problem presented by achieving

[[Page 36824]]

compliance on engines that are technically impossible to retrofit.
    One commenter stated that the EPA should also consider allowing 
companies to choose a mass-based alternative that would ensure 
emissions reductions align with the tons per year reductions upon which 
the EPA based its significant contribution and over-control analyses.
    Response: Based upon the EPA's 2019 NEI emissions inventory data, 
the EPA estimates that a total of 3,005 stationary SI engines are 
subject to the final rule. The EPA recognizes that many low-use engines 
are captured by the 1,000 hp design capacity applicability threshold. 
In the process of reviewing public comments, the EPA reviewed emissions 
averaging plans found in state air quality rules for Colorado, 
Illinois, Louisiana, New Jersey, and Tennessee.\384\ Based on these 
additional reviews, the EPA is finalizing in Sec.  52.41(c) of this 
final rule an emissions limit compliance alternative using facility-
level emissions averaging. Emissions averaging plans will allow 
facility owners and operators to determine how to best achieve the 
necessary emissions reductions by installing controls on the affected 
engines with the greatest emissions reduction potential rather than on 
units with lower actual emissions where the installation of controls 
would be less cost effective. The final rule defines ``facility'' 
consistent with the definition of this term as it generally applies in 
the EPA's NSR and title V permitting regulations,\385\ with one 
addition to make clear that, for purposes of this final rule, a 
``facility'' may not extend beyond the boundaries of the 20 states 
covered by the FIP for industrial sources, as identified in Sec.  
52.40(b)(2). Because a facility cannot extend beyond this geographic 
area, a Facility-Wide Averaging Plan also cannot extend beyond the 20-
state area covered by the FIP.
---------------------------------------------------------------------------

    \384\ See Code of Colorado Regulations, Regulation Number 7 (5 
CCR 1001-9), Part E, Section I.D.5.c., Illinois Administrative Code, 
Title 35, Section 217.390, Louisiana Administrative Code, Title 33, 
Section 2201, New Jersey Administrative Code, Title 7, Chapter 27, 
Section 19.6, and Rules of the Tennessee Dept. of Environment and 
Conservation, Rule 1200-03-27-.09.
    \385\ See 40 CFR 51.165(a)(1)(ii)(A), 51.166(b)(6)(i), and 
52.21(b)(6)(i) (defining ``building, structure, facility, or 
installation'' for Nonattainment New Source Review and Prevention of 
Significant Deterioration permits) and Natural Resources Defense 
Council v. EPA, 725 F.2d 761 (D.C. Cir. 1984) (vacating and 
remanding EPA's categorial exclusion of vessel activities from this 
definition); see also 40 CFR 70.2 (defining ``major source'' for 
title V operating permits).
---------------------------------------------------------------------------

    To estimate the number of facilities that may take advantage of the 
Facility-Wide Averaging Plan provisions, and the number of affected 
units that would install controls under such an emissions averaging 
plan, the EPA conducted an analysis on a subset of the estimated 3,005 
stationary IC engines subject to the final rule. The EPA evaluated the 
reported actual NOX emissions data in tpy from a subset of 
facilities in the covered states using 2019 NEI data for stationary IC 
engines with design capacities of 1,000 hp or greater. The EPA then 
identified a number of facilities that have more than one affected 
engine, calculated each facility's emissions ``cap'' as the total 
NOX emissions (in tpy) allowed facility-wide based on the 
unit-specific NOX emissions limits applicable to all 
affected units at the facility, and identified a number of higher-
emitting engines at each facility that were candidates for having 
controls installed. For engines that EPA identified were likely to 
install controls, the EPA assumed that four stroke rich burn engines, 
four stroke lean burn engines, and two stroke lean burn engines could 
achieve a NOX emissions rate of 0.5 g/hp-hr with the 
installation of SCR based on data obtained from the Ozone Transport 
Commission report entitled Technical Information Oil and Gas Sector 
Significant Stationary Sources of NOX Emissions (October 17, 2012). For 
the remaining engines identified as uncontrolled, the EPA assumed a 
NOX emissions rate of 16 g/hp-hr for all engine types. Thus, 
under the assumed averaging scenarios, engines with controls installed 
would achieve emissions levels below the emissions limits in the final 
rule and would offset the higher emissions from the remaining 
uncontrolled units.
    The EPA then calculated the total facility-wide emissions (in tpy) 
under various assumed averaging scenarios and compared those totals to 
each facility's calculated emissions cap (in tpy) to estimate the 
number of affected units at each facility that would need to install 
controls to ensure that total facility-wide emissions remained below 
the emissions cap. Based on these analyses, the EPA found that 
emissions averaging should allow most facilities to install controls on 
approximately one-third of the engines at their sites, on average, 
while complying with the applicable NOX emissions cap on a 
facility-wide basis. For a more detailed discussion of the EPA's 
analysis and related assumptions, see the Final Non-EGU Sectors TSD.
    The Facility-Wide Averaging Plan provisions that the EPA is 
finalizing provide the flexibility needed to address the concerns about 
the costs of emissions control installations for certain stationary SI 
engines, by allowing facility owners and operators to average emissions 
across all participating units and thus to select the most cost-
effective means for installing the necessary controls (i.e., by 
installing controls on the subset of engines that provide the greatest 
emissions reduction potential at lowest costs and avoiding installation 
of controls on equipment that is infrequently operated or otherwise 
less cost-effective to control).
    An owner or operator of a facility containing more than one 
affected unit may elect to use an EPA-approved Facility-Wide Averaging 
Plan as an alternative means of compliance with the NOX 
emissions limits in Sec.  52.41(c). The owner or operator of such a 
facility must submit a request to the EPA that, among other things, 
specifies the affected units that will be covered by the plan, provides 
facility and unit-level identification information, identifies the 
facility-wide emissions ``cap'' (in tpd) that the facility must comply 
with on a 30-day rolling average basis, and provides the calculation 
methodology used to demonstrate compliance with the identified 
emissions cap. The EPA will approve a request for a Facility-Wide 
Averaging Plan if the EPA determines that the facility-wide emissions 
total (in tpd), based on a 30-day rolling emissions average basis 
during the ozone season, is less than the emissions cap (in tpd) and 
the plan establishes satisfactory means for determining initial and 
continuous compliance, including appropriate testing, monitoring, and 
recordkeeping requirements.
Compliance Assurance Requirements
    The EPA is requiring owners and operators of affected units to 
conduct annual performance tests in accordance with 40 CFR 60.8 to 
demonstrate compliance with the NOX emissions limit in this 
final rule. The EPA is also requiring owners and operators to monitor 
and record hours of operation and fuel consumption and to use 
continuous parametric monitoring systems to demonstrate ongoing 
compliance with the applicable NOX emissions limit. For 
example, owners and operators of engines that utilize layered 
combustion controls will 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, owners and operators must monitor and record parameters such 
as inlet temperature to the catalyst

[[Page 36825]]

and pressure drop across the catalyst. For affected engines that meet 
the certification requirements of Sec.  60.4243(a), however, the 
facility-wide emissions calculations may be based on certified engine 
emissions standards data pursuant to Sec.  60.4243(a), instead of 
performance tests.
    In calculating the facility-wide emissions total during the ozone 
season, affected engines covered by the Facility-Wide Averaging Plan 
must be identified by each engine's nameplate capacity in horsepower, 
its actual operating hours during the ozone season, and its emissions 
rates in g/hp-hr from certified engine data or from the most recent 
performance test results for non-certified engines according to Sec.  
52.41(e).
    Comment: Several commenters stated that semi-annual performance 
testing would not be appropriate due to its high costs and limited 
benefits. One commenter proposed a ``step-down'' testing alternative 
that could be conducted after establishing an engine's initial 
compliance via performance testing. Under this approach, owners and 
operators would conduct one performance test and would only need to 
conduct a second performance test within a given year if the first 
performance test demonstrated that an engine was not meeting the 
applicable emissions standards.
    Another commenter asserted that to test all of its 950 units, a 
minimum of 12 months would be needed rather than the six months the EPA 
had proposed to provide (or five months if the EPA would require one of 
the semi-annual tests to be conducted during the ozone season). The 
commenter stated that the EPA had accounted for these operational 
realities in the past and that under the NSPS and NESHAP, testing is 
generally required only once for every 8,760 hours of run time. The 
commenter asserted that there is no reason to require more frequent 
testing than those required under the NSPS and NESHAP.
    Several commenters requested that the EPA allow for reduction in 
the frequency of testing to once every two years if testing shows that 
NOX emissions are no more than 75 percent of permitted 
NOX emissions limits. In addition, several commenters stated 
that since the rule is intended to address the ozone season, a single, 
annual test is more feasible than semi-annual testing and reporting.
    Response: For the stationary SI engines subject to this final rule, 
the EPA is revising the frequency of required performance tests from a 
semi-annual basis to once per calendar year. As commenters correctly 
pointed out, the emissions limits in these final FIPs only apply during 
the 5-month ozone season and testing once per calendar year should be 
sufficient to confirm the accuracy of the parameters being monitored to 
determine continuous compliance during the ozone season. The EPA also 
agrees with commenters that the annual tests required under the final 
rule need not occur during the ozone season. However, where sources are 
able to do so, we recommend conducting a stack test in the period 
relatively soon before the start of the ozone season. This would 
provide the greatest assurance that the emissions control systems are 
working as intended and the applicable emissions limit will be met when 
the ozone season starts.
    Comment: Commenters generally stated that requiring CEMS would add 
an unnecessary cost and complexity, would provide no emissions 
reduction benefit for the affected units the proposed FIP intends to 
control and are not warranted due to the availability of other 
established methods of compliance assurance, such as parametric 
monitoring and periodic testing. One commenter stated that requiring 
CEMS would add unnecessary CEMS testing obligations. Another commenter 
stated that the costs associated with CEMS and frequent performance 
testing on affected RICE would be as much, if not more, than the costs 
associated with installation and operation of some of the control 
technologies EPA has considered in setting the proposed emissions 
limits. According to one commenter, the EPA has traditionally agreed 
with this viewpoint on the high cost of CEMS, as most stationary 
engines are not currently required under the NSPS or NESHAP to install 
or operate CEMS.
    Another commenter stated that in addition to cost, there are other 
barriers to installing CEMS on RICE across the Pipeline Transportation 
of Natural Gas industry. Many RICE in the Pipeline Transportation of 
Natural Gas industry are located at remote, unstaffed locations, 
meaning that there would be no staff available to respond and react to 
communication or alarms from CEMS.
    Response: The EPA acknowledges the costs associated with the 
installation and maintenance of CEMS at affected units in the Pipeline 
Transportation of Natural Gas industry and agrees that it is not 
necessary to require CEMS for purposes of compliance with the 
requirements of this final rule for this industry. Accordingly, the EPA 
is not finalizing requirements for affected units in this industry 
sector to install or operate CEMS. Instead, the EPA is requiring 
parametric monitoring protocols, as described earlier, coupled with an 
annual performance test, which will ensure that the emissions limits 
are legally and practically enforceable on a continuous basis, and that 
data are recorded, reported, and can be made publicly available, 
ensuring the ability of state and Federal regulators and other persons 
under CAA sections 113 and 304 to enforce the requirements of the Act.
2. Cement and Concrete Product Manufacturing
Applicability
    For cement kilns in the Cement and Cement Product Manufacturing 
industry, the EPA is finalizing the proposed applicability provisions 
without change. The affected units in this industry are cement kilns 
that emit or have a PTE of 100 tpy or more of NOX. The EPA 
received comments regarding the definition of PTE, which we address in 
section VI.C, but no comments concerning the 100 tpy PTE threshold for 
applicability purposes.
Emissions Limitations and Rationale
    As explained in the proposal, the EPA based the proposed emissions 
limits for cement kilns on the types of limits being met across the 
nation in RACT NOX rules, NSPS, air permits, and consent 
decrees. Based on these requirements, the EPA proposed emissions limits 
in the form of mass of pollutant emitted (in pounds) per kiln's clinker 
output (in tons), i.e., pounds of NOX emitted per ton of 
clinker produced during a 30-operating day rolling average period. 
Further, the EPA proposed specific emissions limits for long wet, long 
dry, preheater, precalciner, and combined preheater/precalciner kilns. 
The EPA also proposed a daily source cap limit that would apply to all 
units at a facility. Based on information received from public 
comments, the EPA is removing the daily source cap limit but finalizing 
the emissions limits as proposed in all other respects, as shown in 
Table VI.C-2.

[[Page 36826]]



 Table VI.C-2--Summary of NOX Emissions Limits for Kiln Types in Cement
                   and Concrete Product Manufacturing
------------------------------------------------------------------------
                                                    NOX emissions limit
                    Kiln type                       (lb/ton of clinker)
 
------------------------------------------------------------------------
Long Wet.........................................                    4.0
Long Dry.........................................                    3.0
Preheater........................................                    3.8
Precalciner......................................                    2.3
Preheater/Precalciner............................                    2.8
------------------------------------------------------------------------

    Comment: Numerous commenters raised concerns about designing a 
source cap limit based on average annual production in tons of clinker 
and kiln type. Commenters stated that the source cap limit equation as 
used in a prior action applied to long wet and dry preheater-
precalciner or precalciner kilns and did not include other kiln types. 
Commenters expressed concern that the CAP2015 Ozone Transport equation 
the EPA proposed in this rule could lead to artificially low and 
restrictive daily emissions caps for facilities that experienced a 
temporary decrease in production due to the COVID-19 pandemic, during 
the historical three-year period proposed for use in determining the 
NOX source cap. Also, commenters expressed concern that the 
proposed daily emissions cap limit originated as a local or regional 
limit for a single county and would not be appropriate for national 
application without further evaluation taking into account the specific 
characteristics of cement kilns in other states. One commenter 
suggested more stringent emissions limits than those the EPA had 
proposed for individual kiln types.
    Response: The EPA is not finalizing the proposed daily source cap 
limit as the Agency agrees with the commenters that this proposed limit 
would be unnecessarily restrictive and was based on a formula that did 
not include all kiln types. Given the unusual reduction in cement 
production activities due to the COVID-19 pandemic, production rates 
during the 2019-2021 period are not representative of cement plants 
activities generally. Accordingly, use of the proposed daily source cap 
limit would result in an artificially restrictive NOX 
emissions limit for affected cement kilns, particularly when this 
sector operates longer hours during the spring and summer construction 
season. With respect to those comments supporting more stringent 
emissions limits than those the EPA proposed for individual kiln types, 
we disagree given the significant differences among different kilns in 
design, configuration, age, fuel capabilities, and raw material 
composition. The EPA finds that the ozone season emissions limits for 
individual kiln types listed in Table VI.C-2 will achieve the necessary 
emissions reductions for purposes of eliminating significant 
contribution as defined in section V and is, therefore, finalizing 
these emissions limitations without change.
    Comment: One commenter supported retirement of existing long wet 
kilns and replacement of these kilns with modern kilns. Other 
commenters opposed the phase out and retiring of these kilns, stating 
that many of the screened kilns have SNCR already installed and 
questioning whether replacement of existing long wet kilns is cost-
effective. Some commenters also stated that according to EPA's 
``NOX Control Technologies for the Cement Industry, Final 
Report,'' SNCR is not an appropriate NOX control technique 
for long wet kilns.
    Response: The EPA appreciates the challenges identified by 
commenters, such as site-specific technical evaluation and review and 
significant capital investment associated with undertaking kiln 
conversions or to install new kilns and is not finalizing any 
requirements to replace existing long wet kilns in this rule.
    Comment: Several commenters expressed concern about the supply 
chain issues relevant to the procurement, design, construction, and 
installation of control devices, as well as securing related contracts, 
for the cement industry, particularly when cement sources will be 
competing with the EGU and other industrial sectors for similar 
services. One commenter stated that many preheater/precalciner kilns 
are already equipped with SNCR and that one facility not equipped with 
SNCR is already meeting NOX emissions levels of 1.95 lb/ton 
of clinker or less. The commenter stated that the EPA should revise its 
assessment of potential NOX reductions and cost estimates by 
accurately accounting for existing operating efficiencies and control 
devices at cement kilns.
    Response: The EPA's response to comments on the time needed for 
installation of controls for non-EGU sources is provided in section 
VI.A. Regarding the comment that certain facilities may already have 
SNCR control technology installed, we recognize that many sources 
throughout the EGU sector and non-EGU industries covered by this rule 
may already be achieving enforceable emissions performance commensurate 
with the requirements of this action. This is entirely consistent with 
the logic of our 4-step interstate transport framework, which is 
designed to bring all covered sources within the region of linked 
upwind states up to a uniform level of NOX emissions 
performance during the ozone season. See EME Homer City, 572 U.S. at 
519. Sources that are already achieving that level of performance will 
face relatively limited compliance costs associated with this rule.
Compliance Assurance Requirements
    The EPA received no comments on the proposed test methods and 
procedures provisions for the cement industry. Therefore, we are 
finalizing the proposed test methods and procedures for affected cement 
kilns without change.
    Comment: Commenters generally supported requiring performance 
testing or installation of CEMS on affected cement kilns. Some 
commenters suggested that no performance testing should be required and 
others suggested that performance testing should only be required when 
a title V permit is due for renewal (every 5 years). One commenter 
suggested requiring sources to conduct stack tests during the ozone 
season.
    Response: Affected kilns that operate a NOX CEMS may use 
CEMS data consistent with the requirements of 40 CFR 60.13 in lieu of 
performance tests to demonstrate compliance with the requirements of 
this final rule. For affected kilns subject to this final rule that do 
not employ NOX CEMS, the EPA is adjusting the performance 
testing frequency and requiring kilns to conduct a performance test on 
an annual basis during a given calendar

[[Page 36827]]

year.\386\ The EPA finds that annual performance testing and 
recordkeeping of cement production and fuel consumption during the 
ozone season will assure compliance with the emissions limits during 
the ozone season (May through September) each year for purposes of this 
rule. The required annual performance test may be performed at any time 
during the calendar year. However, where sources are able to do so, we 
recommend conducting a stack test in the period relatively soon before 
the start of the ozone season. This would provide the greatest 
assurance that the emissions control systems are working as intended 
and the applicable emissions limit will be met when the ozone season 
starts.
---------------------------------------------------------------------------

    \386\ 40 CFR 63.11237 ``Calendar year'' defined as the period 
between January 1 and December 31, inclusive, for a given year.
---------------------------------------------------------------------------

    Comment: One commenter stated that CEMS has been used successfully 
at its facility. Another commenter explained that the inside of a 
cement kiln is an extremely challenging environment for making any kind 
of continuous measurement as temperatures are high, and there is a lot 
of dust and tumbling clinker can damage in situ measuring instruments.
    Response: The majority of cement kilns in the United States are 
already equipped with CEMS. However, in response to commenters concerns 
regarding the installation of CEMS, the EPA is finalizing alternative 
compliance requirements in lieu of CEMS. Owners or operators of 
affected emissions units without CEMS installed must conduct annual 
performance testing and continuous parametric monitoring to demonstrate 
compliance with the emissions limits in this final rule. Specifically, 
owners or operators of affected units without CEMS must monitor and 
record stack exhaust gas flow rate, hourly production rate, and stack 
exhaust temperature during the initial performance test and subsequent 
annual performance tests to assure compliance with the applicable 
emissions limit. The owner or operator must then continuously monitor 
and record those parameters to demonstrate continuous compliance with 
the NOX emissions limits.
3. Iron and Steel Mills and Ferroalloy Manufacturing
Applicability
    The EPA is establishing emissions control requirements for the Iron 
and Steel Mills and Ferroalloy Manufacturing source category that apply 
to reheat furnaces that directly emit or have the potential to emit 100 
tpy or more of NOX. After review of all available 
information received during public comment, the EPA has determined that 
there is sufficient information to determine that low-NOX 
burners can be installed on reheat furnaces. As explained further in 
the Final Non-EGU Sectors TSD, the EPA identified 32 reheat furnaces 
with low-NOX burners installed and has concluded that low-
NOX burners are a readily available and widely implemented 
emissions reduction strategy.\387\ This rule defines reheat furnaces to 
include all furnaces used to heat steel product--metal ingots, billets, 
slabs, beams, blooms and other similar products--to temperatures at 
which it will be suitable for deformation and further processing.
---------------------------------------------------------------------------

    \387\ See Final Non-EGU Sectors TSD, Section 4.
---------------------------------------------------------------------------

    Comment: Several industry commenters requested that the EPA not 
include certain iron and steel emissions units--including blast 
furnaces, basic oxygen furnaces (BOFs), ladle and tundish preheaters, 
annealing furnaces, vacuum degassers, taconite kilns, coke ovens, and 
electric arc furnaces (EAFs)--in the final rule as proposed due to, 
among other things, the uniqueness of each emissions unit, various 
design-related challenges, and expected impossibility of successful 
implementation of add-on NOX control technology. Commenters 
expressed concern about requirements to install SCR for all iron and 
steel units for which the EPA proposed emissions limits. The commenters 
stated that iron and steel units had not installed SCR except in a few 
rare instances for experimental reasons and that SCR technology was not 
readily available or known for the iron and steel industry, unlike the 
control technologies expected to be installed in other non-EGU 
industries. Furthermore, commenters stated that SCR had not been 
applied for RACT, BACT, or LAER purposes on iron and steel units.
    Response: In light of the comments we received on the complex 
economic and, in some cases, technical challenges associated with 
implementation of NOX control technologies on certain 
emissions units in this sector, the EPA is not finalizing the proposed 
emissions limits for blast furnaces, BOFs, ladle and tundish 
preheaters, annealing furnaces, vacuum degassers, taconite kilns, coke 
ovens, or EAFs.
    The EPA is aware of many examples of low-NOX technology 
utilized at furnaces, kilns, and other emissions units in other sectors 
with similar stoichiometry, including taconite kilns, blast furnace 
stoves, electric arc furnaces (oxy-fuel burners), and many other 
examples at refineries and other large industrial facilities. The EPA 
anticipates that with adequate time, modeling, and optimization 
efforts, such NOX reduction technology may be achievable and 
cost-effective for these emissions units in the Iron and Steel Mills 
and Ferroalloy Manufacturing sector as well. However, the data we have 
reviewed is insufficient at this time to support a generalized 
conclusion that the application of NOX controls, including 
SCR or other NOX control technologies such as LNB, is 
currently both technically feasible and cost effective on a fleetwide 
basis for these emission source types in this industry. We provide a 
more detailed discussion of the economic and technical issues 
associated with implementation of NOX control technologies 
on these emissions units, including information provided by commenters, 
in section 4 of the Final Non-EGU Sectors TSD.
    Reheat furnaces are the only type of emissions unit within the Iron 
and Steel Mills and Ferroalloy Manufacturing industry that this final 
rule applies to. Low-NOX controls (e.g., low-NOX 
burners) are a demonstrated control technology that many reheat 
furnaces have successfully employed.
    Comment: One commenter claimed that the proposed definition of 
``reheat furnaces'' is overly vague and requested that the EPA amend 
the definition. Specifically, the commenter asserted that the EPA's 
proposed definition does not indicate what counts as ``steel product'' 
and whether this includes only products that have already been 
manufactured into some form before being introduced to a reheat 
furnace, or whether it also includes steel that has never left the 
original production process, such as hot steel coming directly from a 
connected casting process which has not yet been formed into a 
definitive product. The commenter referenced the definition of reheat 
furnaces in Ohio's RACT regulations as an example to consider.
    Response: In response to these comments, the EPA is finalizing a 
definition of reheat furnaces that is consistent with the definition in 
Ohio's NOX RACT regulations. See Ohio Admin. Code 3745-110-
01(b)(35) (March 25, 2022). Specifically, the EPA is defining reheat 
furnaces to mean ``all furnaces used to heat steel product, including 
metal ingots, billets, slabs, beams, blooms and other similar products, 
to temperatures at which it will be suitable for deformation and 
further processing.''

[[Page 36828]]

Emissions Control Requirements, Testing, and Rationale
    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 is finalizing requirements for each 
facility with an affected reheat furnace to design, fabricate and 
install high-efficiency low-NOX burners designed to reduce 
NOX emissions from pre-installation emissions rates by at 
least 40 percent by volume, and to conduct performance testing before 
and after burner installation to set emissions limits and verify 
emissions reductions from pre-installation emissions rates. Each low-
NOX burner shall be designed to achieve at least 40 percent 
NOX reduction from existing reheat furnace exhaust emissions 
rates. Each facility with an affected reheat furnace shall, within 60 
days of conclusion of the post-installation performance test, submit 
testing results to the EPA to establish NOX emissions limits 
over a 30-day rolling average. Each proposed emissions limit must be 
supported by performance test data and analysis.
    In evaluating potential 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 emissions limits for this industry 
in terms of mass of pollutant emitted (pounds) per operating hour 
(hour) (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. Regulated iron and 
steel facilities, including facilities operating reheat furnaces in 
this sector, routinely monitor and keep track of production in terms of 
tons of steel produced per hour (heat rate) as it pertains to each 
facility's rate of iron and steel production. Several facilities, 
including Steel Dynamics, Columbia, Indiana, Cleveland-Cliffs, 
Cleveland, Ohio, and Cleveland-Cliffs, Burns Harbor, Indiana, are 
already operating various types of reheat furnaces with low-
NOX burners and achieving emissions rates as low as 0.11 lb/
mmBtu of NOX. The EPA identified at least nine reheat 
furnaces with a PTE greater than 100 tpy, including slab, rotary 
hearth, and walking beam furnaces, that have installed low-
NOX burners and are achieving various emissions rates.\388\
---------------------------------------------------------------------------

    \388\ Specifically, through a review of title V permits, the EPA 
identified reheat furnaces with low-NOX burners installed 
at Steel Dynamics in Columbia City, Indiana (two furnaces), Steel 
Dynamics in Butler, Indiana (one furnace), Cleveland Cliffs in Burns 
Harbor, Indiana (four furnaces), Cleveland Cliffs in East Chicago, 
Indiana (one furnace), and Cleveland Cliffs in Cleveland, Ohio (one 
furnace). For a further discussion of the limits and information on 
these facilities, see the Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

    Due to variations in the emissions rates that different types of 
reheat furnaces can achieve, the EPA is not finalizing one emissions 
limit for all reheat furnaces and is instead requiring the installation 
of low-NOX burners or equivalent low-NOX 
technology designed to achieve a minimum 40 percent reduction from 
baseline NOX emission levels, together with source specific 
emissions limits to be set thereafter based on performance testing. 
Specifically, the final rule requires that each owner or operator of an 
affected unit submit to the EPA, within one year after the effective 
date of the final rule, a work plan that identifies the low-
NOX burner or alternative low-NOX technology 
selected, the phased construction timeframe by which the owner or 
operator will design, install, and consistently operate the control 
device, an emissions limit reflecting the required 40 percent reduction 
in NOX emission levels, and, where applicable, performance 
test results obtained no more than five years before the effective date 
of the final rule to be used as baseline emissions testing data 
providing the basis for the required emissions reductions. If no such 
data exist, then the owner or operator must perform pre-installation 
testing to establish baseline emissions data.
    Comment: One commenter stated that the standard practice for 
setting NOX limits for iron and steel sources often requires 
consideration of site or unit-specific issues. Similarly, another 
commenter stated that a single limit would not provide an adequate 
basis for establishing NOX emissions limits that will 
universally apply to multiple, unique facilities. The same commenter 
stated that NOX reduction in certain furnaces is routinely 
achievable by combustion controls or measures other than SCR.
    Response: The EPA acknowledges the difficulty in crafting one 
emissions limit for multiple iron and steel facilities and units of 
varying size, age, and design, in light of the unique issues associated 
with varying unit types in this particular industry. We also 
acknowledge that in some cases, reheat furnaces are equipped with 
recently installed, high-efficiency low-NOX burners. Many 
sources throughout the EGU sector and non-EGU industries covered by 
this rule may already be achieving enforceable emissions performance 
commensurate with the requirements of this action. This is entirely 
consistent with the logic of our 4-step interstate transport framework, 
which is designed to bring all covered sources within the region of 
linked upwind states up to a uniform level of NOX emissions 
performance during the ozone season. See EME Homer City, 572 U.S. at 
519. Sources that are already achieving that level of performance will 
face relatively limited compliance costs associated with this rule.
    The EPA is finalizing requirements for reheat furnaces to install 
high-efficiency low-NOX burners designed to reduce 
NOX emissions from pre-installation emissions rates by 40 
percent by volume, and to perform pre- and post-installation 
performance testing at exhaust outlets to determine rate-based 
emissions limits for reheat furnaces in lb/hour, lb/mmBtu, or lb/ton on 
a rolling 30-operating day average. Owners and operators of affected 
units must also monitor NOX emissions from reheat furnaces 
using CEMS or annual performance testing and recordkeeping and operate 
low-NOX burners in accordance with work practice standards 
set forth in the regulatory text. Due to the many types of emissions 
units within the Iron and Steel Mills and Ferroalloy Manufacturing 
industry, and the limited information available at this time regarding 
NOX control options that are achievable for these units, the 
EPA is finalizing requirements only for reheat furnaces at this time.
    Comment: Commenters expressed concern that the proposed emissions 
limits identified both a 3-hour and a 30-day averaging time for the 
same limits and requested that the EPA clarify the averaging time in 
the final rule. Commenters requested that the EPA finalize limits with 
a 30-day averaging time consistent with the requirements for other non-
EGU industries.
    Response: In determining the appropriateness of 30-day rolling 
averaging times, the 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. The EPA also reviewed

[[Page 36829]]

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 and the information provided 
by public commenters, the EPA is requiring a 30-operating day rolling 
average period as the averaging timeframe for reheat furnaces. 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 providing the flexibility needed to 
address fluctuations in operations and production.
Compliance Assurance Requirements
    The EPA is finalizing requirements for each owner or operator of an 
affected unit in the Iron and Steel Mills and Ferroalloy Manufacturing 
industry to use CEMS or annual performance tests and continuous 
parametric monitoring to determine compliance with the 30-day rolling 
average emissions limit during the ozone season. Facilities choosing to 
use CEMS must perform an initial RATA per CEMS and maintain and operate 
the CEMS according to the applicable performance specifications in 40 
CFR part 60, appendix B. Facilities choosing to use testing and 
continuous parametric monitoring for compliance purposes must use the 
test methods and procedures in 40 CFR part 60, appendix A-4, Method 7E, 
or other EPA-approved (federally enforceable) test methods and 
procedures.
    Comment: Several commenters raised concerns with the requirement to 
install and operate CEMS to monitor NOX emissions. 
Commenters cited the high relative costs of installing CEMS, especially 
for smaller units with lower actual emissions, and the complexities 
with installing CEMS on mobile reheat furnaces. Further, commenters 
explained that due to the unique configuration of certain facilities, 
it would be impossible for a CEMS to differentiate emissions from a 
reheat furnace and other units, like waste heat boilers. As an 
alternative to CEMS, commenters requested that the EPA finalize similar 
monitoring and recordkeeping requirements as proposed for the Cement 
and Concrete Product Manufacturing industry in the proposed rule, which 
allow for CEMS or performance testing and recordkeeping. Commenters 
explained that for reheat furnaces that are natural gas-fired, 
emissions can be tracked by relying on vendor guarantees and emissions 
factors and natural gas throughput.
    Response: The EPA reviewed comments received from the industry 
regarding their concerns of affected units within the iron and steel 
mills and ferroalloy manufacturing sector being required to demonstrate 
compliance through CEMS. The EPA acknowledges the cost associated with 
the installation and maintenance of CEMS to demonstrate compliance with 
the finalized emissions standards for reheat furnaces. In this final 
rule, the EPA is revising the compliance assurance requirements to 
provide flexibility to owners or operators of affected units. 
Compliance may be demonstrated through CEMS or annual performance 
testing and continuous parametric monitoring to demonstrate compliance 
with the emissions limits in this final rule. If an affected unit does 
not use CEMS, the final rule requires the owner or operator to monitor 
and record stack exhaust gas flow rate, hourly production rate, and 
stack exhaust temperature during the initial performance test and 
subsequent annual performance tests to assure compliance with the 
applicable emissions limit. The owner or operator must then 
continuously monitor and record those parameters to demonstrate 
continuous compliance with the NOX emissions limits. 
Affected units that operate NOX CEMS meeting specified 
requirements may use CEMS data in lieu of performance testing and 
monitoring of operating parameters. For sources relying on annual 
performance tests and continuous parametric monitoring to assure 
compliance, the EPA is requiring that sources keep records of 
production and fuel usage during the ozone season to assure compliance 
with the emissions limits on a 30-day rolling average basis. To avoid 
challenges in scheduling and availability of testing firms, the annual 
performance test required under this final rule does not have to be 
performed during the ozone season. However, where sources are able to 
do so, we recommend conducting a stack test in the period relatively 
soon before the start of the ozone season. This would provide the 
greatest assurance that the emissions control systems are working as 
intended and the applicable emissions limit will be met when the ozone 
season starts.
4. Glass and Glass Product Manufacturing
Applicability
    The EPA is finalizing regulatory requirements for the Glass and 
Glass Product Manufacturing source category that apply to furnaces that 
directly emit or have a PTE of 100 tpy or more of NOX. For 
this industry, the EPA is finalizing the proposed applicability 
provisions without change.
    Comment: One commenter requested that the applicability threshold 
for glass manufacturing furnaces should be based on a unit's design 
production capacity instead of the proposed applicability criteria 
(i.e., units that directly emit or have the potential to emit 100 TPY 
or more of NOX). The commenter stated that the production 
capacity for glass manufacturing furnaces is a more relevant basis for 
applicability and would focus the EPA analysis on cost-effective 
regulations.
    Response: During the EPA's development of the proposed emissions 
limits, the EPA reviewed the applicability provisions in various state 
RACT NOX rules, air permits, consent decrees, and Federal 
regulations applicable to glass manufacturing furnaces. Most of these 
applicability provisions were expressed in terms of actual emissions or 
PTE. Given the significant differences in the types, designs, 
configurations, ages, and fuel capabilities among glass furnaces, and 
differences in raw material compositions within the sector, the EPA 
finds that applicability criteria based on emissions or potential to 
emit are the most appropriate way to capture higher-emitting glass 
manufacturing furnaces that contribute NOX emissions to 
downwind receptors.
Emissions Limitations and Rationale
    The EPA is finalizing the proposed NOX emissions limits 
for furnaces within the Glass and Glass Product Manufacturing industry, 
except that for flat glass manufacturing furnaces the EPA is finalizing 
an emissions limit slightly lower than the limit we had proposed, based 
on a correction to a factual error in our proposal. For further 
discussion of the basis for the form and level of the final emissions 
limits, see the proposed rule, 87 FR 20036, 20146 (April 6, 2022) 
(discussing EPA review of state RACT rules, NSPS, and other regulations 
applicable to the Glass and Glass Product Manufacturing industry). 
Several comments supported the EPA's effort to regulate sources within 
the Glass and Glass Product Manufacturing industry but also requested 
that the EPA establish more stringent emissions limits for this 
industry.
    Comment: One commenter stated that NOX emissions from 
the Glass and Glass Product Manufacturing industry are not currently 
subject to any Federal NSPS and that the industry is expected to grow 
in the coming years. The commenter stated that while the EPA's proposed 
limits on glass furnaces fell within the ranges of limits required by

[[Page 36830]]

various states and air districts, they fell at the weakest levels 
within those ranges. For example, the commenter stated that the EPA had 
proposed a 4.0 lb/ton NOX emissions limit for container 
glass manufacturing furnaces, while state and local NOX 
emissions limits for these emissions units range from 1 to 4 lb/ton. 
Similarly, the commenter stated that the EPA had proposed a 4.0 lb/ton 
NOX emissions limit for pressed/blown glass manufacturing 
furnaces, while state and local NOX emissions limits for 
these emissions units range from 1.36 to 4 lb/ton, and that EPA had 
proposed a 9.2 lb/ton NOX emissions limit for flat glass 
manufacturing furnaces, while state NOX emissions limits for 
these emissions units range from 5-9.2 lb/ton. The commenter urged the 
EPA to establish emissions limits lower than those the EPA had 
proposed.
    Response: The EPA is finalizing the emissions limits for affected 
units in the glass and glass product manufacturing industry as proposed 
for all but flat glass manufacturing furnaces, for which the EPA is 
finalizing a slightly lower emissions limit to reflect a correction to 
a factual error in our proposal. During the EPA's development of the 
proposed emissions limits, the EPA reviewed the control requirements or 
recommendations and related analyses in various RACT NOX 
rules, air permits, Alternative Control Techniques (ACT) documents, and 
consent decrees to determine the appropriate NOX emissions 
limits for the different types of glass manufacturing furnaces. Based 
on these reviews and given the significant differences in the types, 
designs, configurations, ages, and fuel capabilities among glass 
furnaces, and differences in raw material compositions within the 
sector, the EPA has concluded that it is appropriate to finalize the 
emissions limits for this industry as proposed, except for the limit 
proposed for flat glass manufacturing furnaces. For flat glass 
manufacturing furnaces, the EPA had proposed a NOX emissions 
limit of 9.2 pounds (lbs) per ton of glass pulled but is finalizing a 
limit of 7.0 lbs/ton of glass pulled on a 30-day rolling average basis. 
This is based on our review of specific state RACT NOX 
regulations that contain a 9.2 lbs/ton limit averaged over a single day 
but contain a 7.0 lbs/ton limit over a 30-day averaging period. This 
change aligns the final limit for flat glass manufacturing furnaces 
with the correct averaging time and is consistent with both the state 
RACT regulations that we reviewed \389\ and our evaluation of cost-
effective controls for this industry in the supporting documents for 
the proposed and final rule.
---------------------------------------------------------------------------

    \389\ For example, Pennsylvania's RACT NOX emission 
limits for flat glass furnaces are 7.0 lbs of NOX per ton 
of glass produced on 30-day rolling average. See Title 25, Part I, 
Subpart C, Article III, Section 129.304, available at https://casetext.com/regulation/pennsylvania-code-rules-and-regulations/title-25-environmental-protection/part-i-department-of-environmental-protection/subpart-c-protection-of-natural-resources/article-iii-air-resources/chapter-129-standards-for-sources/control-of-nox-emissions-from-glass-melting-furnaces/section-129304-emission-requirements.
---------------------------------------------------------------------------

    The EPA acknowledges that NOX emissions from some glass 
manufacturing furnaces are subject to control under other regulatory 
programs, such as those adopted by states to meet CAA RACT 
requirements, and that some of these programs have implemented more 
stringent emissions limits than those the EPA is finalizing in these 
FIPs. However, as noted in the preamble to the proposed rule and 
related TSD, many OTR states do not establish specific NOX 
emissions limits for glass manufacturing sources.\390\ See 87 FR 20146. 
In addition to state RACT rules, air permits, ACT documents, and 
consent decrees applicable to this industry, the EPA reviewed reports 
and recommendations from the National Association of Clean Air Agencies 
(NACAA), the European Union Commission, and EPA's Menu of Control 
Measures (MCM) to identify potentially available control measures for 
reducing NOX emissions from the glass manufacturing 
industry. The EPA also reviewed permit data for existing glass 
manufacturing furnaces to identify control devices currently in use at 
these sources. Based on these reviews, we find that the final emissions 
limits for the Glass and Glass Product Manufacturing industry provided 
in Table VI.C.3-1 generally reflect a level of control that is cost-
effective for the majority of the affected units and sufficient to 
achieve the necessary emissions reductions. The Final Non-EGU Sectors 
TSD provides a more detailed explanation of the basis for these 
emissions limits.
---------------------------------------------------------------------------

    \390\ See Proposed Non-EGU Sectors TSD at 56, EPA-HQ-OAR-2021-
0668-0145.

  Table VI.C.3-1--Summary of Finalized NOX Emissions Limits for Furnace
           Unit Types in Glass and Glass Product Manufacturing
------------------------------------------------------------------------
                                                    NOX emissions limit
                                                     (lbs/ton of glass
                   Furnace type                         produced, 30
                                                   operating-day rolling
                                                          average)
------------------------------------------------------------------------
Container Glass Manufacturing Furnace............                    4.0
Pressed/Blown Glass Manufacturing Furnace or                         4.0
 Fiberglass Manufacturing Furnace................
Flat Glass Manufacturing Furnace.................                    7.0
------------------------------------------------------------------------

Alternative Emissions Standards During Periods of Start-Up, Shutdown, 
and Idling
    Comment: Numerous commenters urged the EPA to provide additional 
flexibilities, alternative NOX emissions limits, or 
exceptions to the NOX emissions limits for glass 
manufacturing furnaces during periods of startup, shutdown and idling. 
Commenters requested that the EPA consider excluding days with low 
glass pull (e.g., abnormally low production rate), furnace start-up 
days, furnace maintenance days, and malfunction days from the 
definition of ``operating day'' to allow for exclusion of these days 
from the calculation of an emissions unit's 30-operating day rolling 
average emissions. The commenters argued that because the glass furnace 
temperature is much lower during these periods than they are during 
normal operating conditions, it would be technologically infeasible to 
equip furnaces with NOX control devices including SCR. 
Commenters also stated that because control equipment cannot be 
operated during these periods without damaging the equipment, it would 
be very difficult or impossible to meet the proposed NOX 
limits during these periods.
    Response: After review of the comments received and the EPA's 
assessment of current practices within

[[Page 36831]]

the glass manufacturing industry, the EPA is establishing provisions 
for alternative work practice standards and emissions limits that may 
apply in lieu of the emissions limits in Sec.  52.44(c) during periods 
of start-up, shutdown, and idling. The emissions limits for glass 
melting furnaces in Sec.  52.44(c) do not apply during periods of 
start-up, shutdown, and/or idling at affected units that comply instead 
with the alternative requirements for start-up, shutdown, and/or idling 
periods specified in Sec.  52.44(d), (e), and/or (f), respectively. The 
EPA has modeled these alternative requirements that apply during 
startup, shutdown, and idling to some extent on State RACT requirements 
identified by commenters.\391\ These alternative work practice 
standards adequately address the seven criteria that the EPA has 
recommended states consider when establishing appropriate alternative 
emissions limitations for periods of startup and shutdown.\392\ We 
provide a more detailed evaluation of these provisions in the TSD 
supporting this final rule.
---------------------------------------------------------------------------

    \391\ See Pennsylvania Code, Title 25, Part I, Subpart C, 
Article III, Sections 129.305-129.307 (effective June 19, 2010), 
available at https://www.pacodeandbulletin.gov/Display/pacode?file=/secure/pacode/data/025/chapter129/chap129toc.html&d=reduce and San 
Joaquin Valley Unified Air Pollution Control District, Rule 4354, 
``Glass Melting Furnaces,'' sections 5.5-5.7 (amended May 19, 2011), 
available at https://www.valleyair.org/rules/currntrules/R4354%20051911.pdf.
    \392\ See 80 FR 33840, 33914 (June 12, 2015) (identifying the 
EPA's recommended criteria for developing and evaluating alternative 
emissions limitations applicable during startup and shutdown).
---------------------------------------------------------------------------

    Specifically, each owner or operator of an affected unit seeking to 
comply with alternative work practice standards in lieu of emissions 
limits during startup or shutdown periods must submit specific 
information to the Administrator no later than 30 days prior to the 
anticipated date of startup or shutdown. The required information is 
necessary to ensure that the furnace will be properly operated during 
the startup or shutdown period, as applicable. The final rule 
establishes limits on the number of days when the owner or operator may 
comply with alternative work practice standards in lieu of emissions 
limits during startup and shutdown, depending on the type of glass 
furnace. Additionally, the owner or operator must maintain operating 
records and additional documentation as necessary to demonstrate 
compliance with the alternative requirements during startup or shutdown 
periods. For startups, the owner or operator must place the emissions 
control system in operation as soon as technologically feasible to 
minimize emissions. For shutdowns, the owner or operator must operate 
the emissions control system whenever technologically feasible to 
minimize emissions.
    For periods of idling, the owner or operator of an affected unit 
may comply with an alternative emissions limit calculated in accordance 
with a specific equation to limit emissions to an amount (in pounds per 
day) that reflects the furnace's permitted production capacity in tons 
of glass produced per day. Additionally, the owner or operator must 
maintain operating records as necessary to demonstrate compliance with 
the alternative emissions limitations during idling periods. During 
idling, the owner or operator must operate the emissions control system 
to minimize emissions whenever technologically feasible.
All-Electric Glass Furnaces
    The EPA solicited 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 also 
requested 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.\393\ The EPA received numerous comments 
from the glass industry regarding their concerns with replacing an 
existing glass manufacturing furnace with an all-electric melter. The 
commenters stated that various operational restrictions present within 
all-electric furnaces prevent these units from being implemented 
throughout the industry, including limited glass production output, 
reduced glass furnace life, and increased glass plant operating cost 
due to high levels of electric current usage. Based on the EPA's review 
of comments submitted on this issue, the EPA has decided not to 
establish any requirements to replace existing glass manufacturing 
furnaces with all-electric furnaces at this time. We provide in the 
following paragraphs a summary of the comments and the EPA's responses 
thereto.
---------------------------------------------------------------------------

    \393\ See definitions in 40 CFR part 60, subpart CC.
---------------------------------------------------------------------------

    Comment: One commenter stated that the lifetime of an all-electric 
glass melting furnace is only about three to five years before it must 
be rebricked, compared to well-maintained natural gas or hybrid furnace 
that may be operated continuously for as long as fifteen to twenty 
years between rebricking events. The commenter also states that 
electric furnaces for manufacture of glass containers are limited to a 
maximum glass production of about 120 tons per day, which is a stark 
contrast to large natural gas fired glass melting furnaces, which are 
capable of producing over 400 tons of glass per day. The commenter also 
stated that the cullet percentage is greatly reduced in all-electric 
furnaces which increases energy consumption in the affected facility.
    Response: At proposal, the EPA solicited comment on whether it is 
feasible or appropriate for owners or operators of existing glass 
manufacturing furnaces to phase out and retire their units and replace 
them with less emitting units like all-electric furnace installations. 
As explained in the Final Non-EGU Sectors TSD, over the last few 
decades the demand for flat, container, and pressed/blown glass has 
continued to grow annually. Nitrogen oxides remain one of the primary 
air pollutants emitted during the production and manufacturing of glass 
products. However, no current Federal CAA regulation controls 
NOX emissions from the industry on a category-wide 
basis.\394\ Therefore, the glass manufacturing industry has conducted 
various pollution prevention and research efforts to help identify 
preferred techniques for the control of NOX. Some of these 
studies revealed recent trends to control NOX emissions in 
the glass industry, including the use of all-electric glass furnaces. 
We understand based on the comments received from the glass 
manufacturing industry that significant differences exist in the 
design, configuration, age, and replacement cost of glass furnaces and 
in the feasibility of controls and raw material compositions. These 
differences as well as the production limitations present with all-
electric furnaces create difficulties in implementing all-electric 
furnaces across the industry while keeping up with glass product 
demands. Therefore, the EPA is not mandating any requirement for owners 
or operators of existing glass manufacturing furnaces to replace their 
units with all-electric furnaces.
---------------------------------------------------------------------------

    \394\ See Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

Combustion Modification and Post-Combustion Modification Control 
Devices
    According to the EPA's ``Alternative Control Techniques Document--
NOX Emissions from Glass

[[Page 36832]]

Manufacturing,'' \395\ glass manufacturing furnaces may utilize 
combustion modifications equivalent to low-NOX burners and 
oxy-firing. At proposal, the EPA solicited comments 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 or operate a post-combustion 
modifications control device like SNCR or SCR to further improve their 
NOX removal efficiency. The EPA received numerous comments 
from the glass industry that detailed the differences present in glass 
furnace designs, operations and finished product that influenced the 
type of combustion modification or post-combustion modification control 
device that is feasible for such unit. Several commenters have 
requested that the EPA focus on establishing an emissions limit rather 
than specifying the use of a particular control technology given the 
significant differences across glass furnaces. As a result of the 
comments received, the EPA is not specifically requiring affected units 
to install combustion modification and post-combustion controls to meet 
the finalized emissions limits. The EPA is finalizing the emissions 
limits as proposed, which may be met with combustion modifications 
(e.g., low-NOX burners, oxy-firing), process modifications 
(e.g., modified furnace, cullet preheat), and/or post-combustion 
controls (SNCR or SCR) and thus provide sources some flexibility to 
choose the control technology that works best for their unique 
circumstances.
---------------------------------------------------------------------------

    \395\ EPA, Alternative Control Techniques Document--
NOX Emissions from Glass Manufacturing, EPA-453/R-94-037, 
June 1994.
---------------------------------------------------------------------------

    Comment: Multiple commenters responded to EPA's request for 
comments by stating it is unnecessary and unhelpful for the proposed 
rule to specify use of particular post-combustion control device. The 
commenters note that various flat glass furnaces have a variety of 
combustion and post-combustion control options. Each furnace is 
different in its design, operations, and finished product produced. The 
commenters state that it is more appropriate for EPA to establish an 
emissions limit in the proposed rule than it is for the EPA to specify 
use of a particular control technology.
    Response: In response to these comments, the EPA is not 
establishing any requirements for affected units to install specific 
control technologies to meet the emissions limits. The EPA is 
finalizing the limits as proposed to offer sources some flexibility to 
choose the control technology that works best for their unique 
circumstances.
Compliance Assurance Requirements
    The EPA proposed to require owners or operators of an affected 
facility that is subject to the NOX emissions standards for 
glass manufacturing furnaces to install, calibrate, maintain and 
operate a CEMS for the measurement of NOX emissions 
discharged. The EPA also solicited comments on alternative monitoring 
systems or methods that are equivalent to CEMS to demonstrate 
compliance with the emissions limits. The EPA received numerous 
comments from the glass industry expressing concern with any 
requirement to use CEMS at affected units. After review of the comments 
received and EPA's assessment of practices conducted within the glass 
manufacturing industry, the EPA is finalizing compliance assurance 
requirements that allow affected glass manufacturing furnaces to 
demonstrate compliance through annual testing or use CEMS, or similar 
alternative monitoring system data in lieu of a performance test. The 
EPA is also establishing recordkeeping provisions that require owners 
or operators of affected units to conduct parametric monitoring of fuel 
use and glass production during performance testing to assure 
continuous compliance on a 30-operating day rolling average.
    Comment: Commenters representing the glass industry stated that a 
requirement to install and operate CEMS would present significant costs 
and technical complexities in a situation where emissions can be 
effectively monitored using stack testing rather than continuous 
monitoring. Commenters also objected to the EPA's proposal to require 
CEMS together with semi-annual stack testing. Commenters stated that a 
requirement to both operate CEMS and conduct semi-annual testing would 
be unnecessary and excessive and would not provide commensurate benefit 
unless a facility's emissions are near or above the proposed emissions 
limit. Commenters requested that owners or operators of affected units 
be allowed to use alternative monitoring systems, e.g., parametric 
emissions monitoring. The commenters stated that parametric monitoring 
requires less initial and ongoing manpower requirements, has lower 
capital and operating costs than CEMS, does not require spare parts, 
and is accurate over a mapped range.
    Response: The EPA is establishing compliance assurance requirements 
that provide flexibility to owners or operators of affected units. 
Compliance with the emissions limits in this final rule may be 
demonstrated through CEMS or via annual performance test and continuous 
parametric monitoring. If an affected unit does not use CEMS, the final 
rule requires the owner or operator to monitor and record stack exhaust 
gas flow rate, hourly production rate, and stack exhaust temperature 
during the initial performance test and subsequent annual performance 
tests to assure compliance with the applicable emissions limit. The 
owner or operator must then continuously monitor and record those 
parameters to demonstrate continuous compliance with the NOX 
emissions limits. Affected units that operate NOX CEMS 
meeting specified requirements may use CEMS data in lieu of performance 
testing and monitoring of operating parameters. To avoid challenges in 
scheduling and availability of testing firms, the annual performance 
test required under this final rule does not have to be performed 
during the ozone season.
5. Boilers at Basic Chemical Manufacturing, Petroleum and Coal Products 
Manufacturing, Pulp, Paper, and Paperboard Mills, Iron and Steel and 
Ferroalloys Manufacturing, and Metal Ore Mining facilities
Applicability
    The EPA is finalizing regulatory requirements for the Iron and 
Steel Mills and Ferroalloy Manufacturing industry, Basic Chemical 
Manufacturing industry, Petroleum and Coal Products Manufacturing 
industry, Pulp, Paper, and Paperboard Mills industry, and the Metal Ore 
Mining industry that apply to boilers that have a design capacity of 
100 mmBtu/hr or greater. The Non-EGU Screening Assessment memorandum 
developed in support of Step 3 of our proposal identified emissions 
from large boilers in certain industries (i.e., those projected to emit 
more than 100 tpy of NOX in 2026) as having adverse impacts 
on downwind receptors. As discussed in the proposed rule, we developed 
applicability criteria for boilers based on design capacity (i.e., heat 
input), rather than on potential emissions, because use of a boiler 
design capacity of 100 mmBtu/hr reasonably approximates the 100 tpy 
threshold used in the Non-EGU Screening Assessment memorandum to 
identify impactful boilers. In this final rule, we are establishing the 
heat input-based applicability criteria described in our proposal, with 
some adjustments as explained further in this section. Additionally, we 
have determined that boilers meeting these applicability

[[Page 36833]]

criteria exist within the following five industries: Basic Chemical 
Manufacturing, Petroleum and Coal Products Manufacturing, Pulp, Paper, 
and Paperboard Mills, Metal Ore Mining, and Iron and Steel Mills and 
Ferroalloy Manufacturing.
    As we explained in the proposed rule, the potential emissions from 
industrial boilers with a design capacity of 100 mmBtu/hr or greater 
burning coal, residual or distillate oil, or natural gas can equal or 
exceed the 100 tpy threshold that we used to identify impactful boilers 
within the Non-EGU Screening Assessment memorandum. We are finalizing 
NOX emissions limits that apply to boilers with design 
capacities of 100 mmBTU/hr or greater located at any of the five 
identified industries in any of the 20 covered states with non-EGU 
emissions reduction obligations. In response to comments on our 
proposed rule, however, the EPA is finalizing a low-use exemption for 
industrial boilers that operate less than 10 percent per year and 
provisions for EPA approval of alternative emissions limits on a case-
by-case basis, where specific criteria are met. Additionally, only 
boilers that combust, on a BTU basis, 90 percent or more of coal, 
residual or distillate oil, natural gas, or combinations of these fuels 
are subject to the requirements of these final FIPs.
    The EPA has determined that boilers meeting the applicability 
criteria of this section exist within the five industrial sectors 
identified in Table VI.C.5-1:

  Table VI.C.5--1: Non-EGU Industries With Large Boilers and Associated
                               NAICS Codes
------------------------------------------------------------------------
                       Industry                            NAICS code
------------------------------------------------------------------------
Basic Chemical Manufacturing.........................             3251xx
Petroleum and Coal Products Manufacturing............             3241xx
Pulp, Paper, and Paperboard Mills....................             3221xx
Iron and Steel and Ferroalloys Manufacturing.........             3311xx
Metal Ore Mining.....................................             2122xx
------------------------------------------------------------------------

    Comment: Several commenters requested that the EPA establish PTE-
based applicability criteria for boilers as it had proposed to do for 
other non-EGU sectors and stated that using heat input as the basis for 
determining applicability would result in low-emitting boilers being 
subject to the final rule's control requirements. Commenters stated 
that the EPA should provide a low-use exemption for infrequently run 
units because these units produce a lower amount of emissions.
    Response: The EPA is finalizing applicability criteria for boilers 
based on boiler design capacity for a number of reasons. First, Federal 
emissions standards applicable to boilers \396\ and all of the state 
RACT rules that we reviewed contain applicability criteria based on 
boiler design capacity. Second, as explained in the Final Non-EGU 
Sectors TSD, most boilers with design capacities of 100 mmBTU/hr or 
greater that are fueled by coal, oil, or gas have the potential to emit 
100 tpy or more of NOX. Thus, use of a boiler design 
capacity of 100 mmBtu/hr for applicability purposes reasonably 
approximates the 100 tpy threshold used in the Non-EGU Screening 
Assessment memorandum to identify impactful boilers. Finally, use of a 
boiler's design capacity for applicability purposes facilitates 
applicability determinations given that a boiler's design capacity is, 
in most cases, clearly indicated by the manufacture on the unit's 
nameplate.
---------------------------------------------------------------------------

    \396\ See, e.g., 40 CFR 60.44b (subpart Db, Standards of 
Performance for Industrial-Commercial-Institutional Steam Generating 
Units).
---------------------------------------------------------------------------

    In response to the comments expressing concern that infrequently-
operated boilers would be captured by the EPA's proposed applicability 
criteria, the EPA is finalizing a low-use exemption for industrial 
boilers that operate less than 10 percent per year on an hourly basis, 
based on the three most recent years of use and no more than 20 percent 
in any one of the three years. Such boilers will be exempt from the 
emissions limits in these FIPs provided they operate less than 10 
percent per year, on an hourly basis, based on the three most recent 
years of use and no more than 20 percent in any one of the three years, 
but will have recordkeeping obligations. The EPA finds it appropriate 
to exempt such low-use boilers from the emissions limits in this final 
rule because the amount of air pollution emitted from a boiler is 
directly related to its operational hours, and installation of controls 
on infrequently operated units results in reduced air quality benefits.
    Comment: Commenters asked whether the EPA's proposed emissions 
limits for boilers would apply to emissions units that burn fuels other 
than coal, residual or distillate oil, or natural gas. For example, one 
commenter stated that some biomass boilers start up by co-firing oil or 
gas and that some NOX controls such as low-NOX 
burners (LNB) cannot be used on biomass boilers. The commenter 
requested clarification on whether boilers burning biomass would be 
covered by the EPA's proposed requirements. Other commenters noted that 
some industrial boilers burn natural gas in conjunction with other 
gaseous fuels, such as hydrogen/methane off-gas and vent gas from 
various on-site processes, and may not be able to meet the EPA's 
proposed 0.08 lb/mmBtu NOX emissions limit for boilers 
burning natural gas. One commenter stated that it operated a boiler 
that burns hazardous waste and is subject to 40 CFR part 63, subpart 
EEE, National Emission Standards for Hazardous Air Pollutants from 
Hazardous Waste Combustors, and that this boiler uses natural gas for 
start-up and at other times to stabilize operations but also combusts 
other fuels such as liquid waste. The commenter asserted that such 
boilers should not be covered by the final rule.
    Response: In recognition and consideration of comments received on 
our proposal, the EPA is finalizing requirements for boilers that apply 
only to boilers burning 90 percent or more coal, residual or distillate 
oil, or natural gas or combinations of these fuels on a heat-input 
basis. Public commenters presented information indicating that the 
burning of fuels other than coal, residual or distillate oil, or 
natural gas at levels exceeding 10 percent may interfere with the 
functions of the control technologies that may be necessary to the meet 
the final rule, like SCR. The EPA does not have sufficient information 
at this time to conclude that units burning more than 10 percent fuels 
other than coal, residual or distillate oil, or natural gas can operate 
the necessary controls effectively and at a reasonable cost. Therefore, 
boilers that burn greater than 10 percent fuels other than coal, 
residual or distillate oil,

[[Page 36834]]

natural gas, or combinations of these three fuels are not subject to 
the emissions limits and other requirements of this final rule.
    Comment: Some commenters claimed that the EPA cannot include 
emissions limits for boilers that burn combinations of coal, residual 
or distillate oil, and natural gas, because the EPA did not propose 
limits for such boilers. Other commenters suggested it would be 
appropriate to establish emissions limits for such boilers as long as 
the EPA provides criteria for establishing such emissions limits.
    Response: The EPA disagrees with the claim that boilers burning 
combinations of coal, residual or distillate oil, or natural gas cannot 
be covered by the final FIP because the EPA did not propose specific 
emissions limits for these boilers and agrees with commenters who 
stated that the EPA's proposed emissions limits can be extended to such 
boilers provided the EPA provides criteria for doing so. The 
applicability criteria in the final rule cover boilers burning 
combinations of coal, residual or distillate oil, or natural gas and 
include a methodology for determining the emissions limits for such 
units based on a simple formula that correlates the amount of heat 
input expended while burning each fuel with the corresponding emissions 
limit for that particular fuel. For example, a boiler with a heat input 
of 85 percent natural gas and 15 percent distillate oil would be 
subject to an emissions limit derived by multiplying the natural gas 
emissions limit by 0.85 and adding to that the distillate oil emissions 
limit multiplied by 0.15. Thus calculated, the NOX emissions 
limits for boilers burning combinations of coal, residual or distillate 
oil, or natural gas are consistent with the NOX emissions 
limits identified in our proposed rule for each of these individual 
fuels.
Emissions Limitations and Rationale
    The EPA is finalizing all of the proposed NOX emissions 
limits for industrial boilers and adding a formula for calculating 
emissions limits for multi-fueled units as shown in Table VI.C.5-2. The 
emissions limits apply to boilers with design capacities of 100 mmBtu/
hr or greater located at any of the five industries identified in Table 
II.A-1 within any of the 20 states covered by the non-EGU requirements 
of this final rule.

     Table VI.C.5-2--NOX Emissions Limits for Boilers >100 mmBtu/hr
                   [Based on a 30-day rolling average]
------------------------------------------------------------------------
                                         Emissions limit (lbs NOX/mmBtu)
               Unit type
------------------------------------------------------------------------
Coal...................................  0.20.
Residual oil...........................  0.20.
Distillate oil.........................  0.12.
Natural gas............................  0.08.
Multi-fueled unit......................  Limit derived by formula based
                                          on heat input contribution
                                          from each fuel.
------------------------------------------------------------------------

    Additional information on the EPA's derivation of these proposed 
emissions rates for boilers is provided in the Final Non-EGU Sectors 
TSD.
    Comment: Some commenters noted that many boilers are already 
subject to other state and Federal controls, and that programs such as 
RACT, NSR, BACT, NSPS, and maximum achievable control technology (MACT) 
are all achieving emissions reductions from boilers.
    Response: The EPA acknowledges that some affected units may already 
be meeting the emissions limits established in this rule as a result of 
controls installed to comply with other regulatory programs, such as 
the CAA's RACT requirements. However, emissions from the universe of 
boilers subject to the applicability requirements of this final rule 
are not being uniformly reduced by these programs to the same extent 
that the limits we are adopting will require, nor for the same reason, 
which is to mitigate the impact of emissions from upwind sources on 
downwind locations that are experiencing air quality problems. The EPA 
has determined that the limits we are finalizing in this action are 
readily achievable and are already required in practice in many parts 
of the country.
    Regarding RACT controls, some of the sources covered by the final 
rule are not subject to RACT requirements because RACT is only 
applicable to sources located in ozone nonattainment areas and in the 
OTR, and many sources covered by the final rule are not located within 
such jurisdictions. Regarding sources that are subject to RACT, we note 
that unlike RACT requirements applicable to sources of VOCs, where a 
majority of such sources are covered by state RACT rules adopted to 
conform with uniform ``presumptive'' limits contained within the EPA's 
Control Technique Guidelines (CTGs), in most cases presumptive 
NOX emissions limits have not been established for 
industrial sources of this pollutant. In light of this, NOX 
RACT requirements are primarily determined on a state-by-state basis 
and exhibit a range of stringencies as determined by each state. 
Additionally, RACT requirements tend to become more stringent with the 
passage of time as existing control options are improved, and new 
options become available. Thus, older RACT determinations may not be as 
stringent as more recent determinations made for similar equipment 
types. As noted in our proposal, we based our NOX emissions 
limits for coal, residual or distillate oil, and natural gas-fired 
industrial boilers on RACT limits that are already in place in many 
areas of the country.
    Regarding NSR control requirements, we note that the NSR program 
was created by the 1977 amendments to the CAA and applies only to new 
or modified stationary sources. Many of the boilers covered by the 
applicability requirement of this final rule were initially installed 
or last modified prior to 1977 and have not undergone NSR analysis, 
such as a BACT analysis for sources located within an attainment area 
or a LAER analysis for sources located within nonattainment areas. 
Additionally, BACT and LAER determinations made many years ago are not 
likely to be as stringent as more recent determinations.
    Regarding NSPS requirements, 40 CFR part 60, subpart Db, Standards 
of Performance for Industrial-Commercial-Institutional Steam Generating 
Units, contains NOX emissions limits for boilers with 
capacities of 100 mmBTU/hr or greater that were constructed or modified 
after June 19, 1984, and so boilers constructed or modified prior to 
that date are not subject to its requirements. Additionally, the limits 
for coal, residual or distillate oil, and

[[Page 36835]]

gas-fired units are not as stringent as more recent limits adopted by 
states pursuant to RACT control obligations.
    Lastly, MACT controls are primarily designed to reduce emissions of 
hazardous air pollutants, not to reduce NOX emissions. We 
anticipate the MACT program's boiler tune-up requirement should reduce 
NOX emissions to some extent, but not to the extent that 
compliance with the limits adopted within this final rule will achieve.
    Comment: One commenter noted that a 2017 OTC survey found that 
boilers, including those used in the paper products, chemical, and 
petroleum industries, are already required to achieve more stringent 
limits, and pointed to limits for distillate oil that are lower than 
what the EPA considered in developing the proposal. The commenter also 
noted that California's South Coast Air Quality Management District has 
adopted a facility-wide NOX emissions limit of 0.03 lb/mmBtu 
at petroleum refineries. The commenter noted that CEMs data shows a 
residual oil-fired boiler at the Ravenswood Steam Plant in New York 
achieves an average NOX emissions rate of 0.0716 lb 
NOX/MMBtu and that CEMS data shows that a gas-fired boiler 
in Johnsonville, Tennessee, achieves an average NOX 
emissions rate of 0.0058 lb NOX/mmBTU. Regarding coal-fired 
boilers, the commenter stated that a coal boiler at the Ingredion 
Incorporated Argo Plant in Illinois achieves an average NOX 
emissions rate of 0.1153 lb NOX/MMBtu with selective non-
catalytic control technology, and the Axiall Corporation facility in 
West Virginia achieves a 0.1162 lb/mmBtu using low-NOX 
burner technology with overfire air. The commenter also noted that more 
than half of the gas-fired boilers included in the air markets program 
database already emit NOX at rates below the EPA's proposed 
emissions rate, and that the RACT/BACT/LAER Clearinghouse (RBLC) shows 
more stringent limits for gas boilers than the limits the EPA proposed, 
with many facilities being required to meet a NOX limit of 
less than 0.0400 lb/mmBtu.
    Response: The EPA's intent was not to set the NOX 
emissions limits for coal, residual or distillate oil, and natural gas-
fired boilers to match the lowest levels required elsewhere by state or 
local authorities, but rather to establish limits that are commensurate 
with broadly applicable RACT limits currently in place in a number of 
states as noted within our proposal. The limits we selected were not 
the most stringent of the state RACT rules we reviewed but were 
relatively close to that value. We did not select the most stringent 
limits because such limits may reflect case-specific technological and 
economic feasibility considerations that do not apply more broadly 
across the industry. Furthermore, although the EPA acknowledges that 
some industrial boilers powered by coal, residual or distillate oil, 
natural gas, or combinations of these fuels can meet very low 
NOX emissions limits as noted by the commenter, it is 
unlikely that all such units could meet these limits given case-
specific considerations such as boiler design and operation, some of 
which limit the types of control technology that may be available to a 
particular unit.
a. Coal-Fired Industrial Boilers
    As we proposed, coal-fired industrial boilers subject to the 
applicability requirements of this section are required to meet a 
NOX emissions limit of 0.2 lb/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 retrofit with equipment to meet this emissions limit. As 
we explained in our proposal, many states containing ozone 
nonattainment areas or located within the OTR have already adopted RACT 
emissions limits similar to or more stringent than the limits in this 
final rule, and most of those RACT limits apply statewide and extend to 
boilers located at commercial and institutional facilities, not just to 
boilers located in the industrial sector.
    Comment: One commenter noted that the coal-fired boilers it 
operates already use combustion controls to reduce NOX 
emissions and contended that the effectiveness of SNCR on these boilers 
is unknown but would likely be on the low end of the control 
effectiveness range because they experience variable loads, which would 
compromise the proper functioning of an SNCR control system. The 
commenter stated that the only way their coal-fired boilers would be 
able to comply with the EPA's proposed NOX limit would be to 
install SCR. The commenter added that for coal-fired industrial boilers 
with a heat input rating of 100 MMBtu/hr or more, a review of the 
available RBLC records indicates that out of the 23 RBLC entries 
identified, nine units (less than half) were subject to an emissions 
limit at or below 0.2 lb/mmBtu, and eight of these nine units were 
equipped with SNCR. The commenter stated that based on a review of the 
available data in the RBLC and given the technical difficulties and low 
control efficiencies when applying SNCR to swing boilers, the EPA's 
proposed limit for coal firing does not appear achievable for 
industrial coal-fired boilers that experience load swings unless SCR is 
installed. Other commenters stated that while there have been recent 
advancements in SNCR technology, such as the setting up of multiple 
injection grids and the addition of sophisticated CEMs-based feedback 
loops, implementing SNCR on industrial load-following boilers continues 
to pose several technical challenges, including lack of achievement of 
optimal temperature range for the reduction reactions to successfully 
complete, and inadequate reagent dispersion in the injection region due 
to boiler design which can lead to significant amounts of unreacted 
ammonia exhausted to the atmosphere (i.e., large ammonia slip). The 
commenter noted that at least one pulp mill boiler had to abandon its 
SNCR system due to problems caused by poor dispersion of the reagent 
within the boiler, and that SNCR has yet to be successfully 
demonstrated for a pulp mill boiler with constant swing loads.
    Response: To the extent the commenter's concerns pertain primarily 
to SNCR control technology, we note that the final rule does not 
mandate the use of any particular type of control technology and that 
other types of control equipment such as SCR should be examined as a 
means for meeting the final emissions limits. The EPA acknowledges that 
some coal-fired industrial boilers subject to this section of the final 
rule may need to install SCR to meet the NOX emissions 
limits. This is reflected in our evaluation of costs for the non-EGU 
sector contained within the Non-EGU Screening Assessment memorandum and 
the cost calculations for the final rule discussed in section V and the 
Memo to Docket--Non-EGU Applicability Requirements and Estimate 
Emissions Reductions and Costs. We note that although the RBLC contains 
information on emissions limits and control technology for some units, 
it only provides information on a relatively small number of units 
subject to NOX emissions limits and operating NOX 
controls. Additionally, our final rule provides an exemption for units 
that operate infrequently (i.e., ``low-use boilers''), and also allows 
a facility owner or operator to submit a request for a case-by-case 
alternative emissions limit in cases where compliance with the 
emissions limit in this final rule is technically impossible or would 
result in extreme economic hardship. We note that non-EGU boilers share 
many similarities with EGU boilers, many of which already operate SCR 
to control NOX emissions or will be required to

[[Page 36836]]

install and operate SCR systems under the requirements for EGUs 
contained in this final rule. Lastly, we note that information 
collected during the development of updates to the EPA's MACT 
requirements for industrial, commercial, and institutional (ICI) 
boilers indicates that over 150 ICI boilers have installed SCR control 
systems to reduce their NOX emissions. This information is 
available in the docket for this final rule.
    All affected units must install and operate NOX control 
equipment as necessary to meet the applicable emissions limits in the 
final rule, except that if the owner or operator requests, and the EPA 
approves, a case-by-case emissions limit based on a showing of 
technical impossibility or extreme economic hardship, the affected unit 
would be required to comply with the EPA-approved case-by-case 
emissions limit instead.
b. Residual or Distillate Oil-Fired Industrial Boilers
    Most oil-fired boilers are fueled by either residual (heavy) oil or 
distillate (light) oil. We proposed a NOX emissions limit of 
0.2 lb/mmBtu \397\ for residual oil-fired boilers and proposed a 
NOX emissions limit of 0.12 lb/mmBtu for distillate oil-
fired boilers. We are finalizing both limits as proposed, based on a 
30-day rolling average. As with coal-fired industrial boilers, a number 
of combustion and post-combustion NOX control technologies 
exist that should generally enable facilities meeting the applicability 
criteria of this section to meet these emissions limits, and the Final 
Non-EGU Sectors TSD identifies numerous states that have already 
adopted emissions limits similar to the limits in this final rule. 
There are relatively few boilers fueled by residual or distillate oil 
within the industries affected by this final rule that meet the 
applicability criteria of this section, and we received relatively few 
comments regarding our proposed emissions limits for them.
---------------------------------------------------------------------------

    \397\ Section 52.45(c) of the regulatory text in our proposed 
rule identified a proposed emissions limit of 0.15 lb/mmBtu for 
residual oil-fired boilers, but the emissions limit that we intended 
to propose for this equipment and discussed both in the preamble to 
the proposed rule and in the TSD supporting the proposed rule was 
0.20 lb/mmBtu.
---------------------------------------------------------------------------

c. Natural Gas-Fired Industrial Boilers
    We proposed a NOX emissions limit of 0.08 lb/mmBtu based 
on a 30-day rolling average for natural gas-fired boilers meeting the 
applicability criteria of this section, and we are finalizing this 
emissions limit and averaging time as proposed. As explained in our 
proposal, numerous combustion and post-combustion NOX 
control technologies exist that should generally enable facilities 
meeting the applicability criteria of this section to meet this 
emissions limit. Additionally, many states have already adopted 
emissions limits similar to the emissions limit in this final rule, and 
some natural gas-fired industrial boilers may be able to meet the 0.08 
lb/mmBtu emissions limit by modifying existing NOX control 
equipment installed to meet the requirements in 40 CFR 60.44b (subpart 
Db of 40 CFR part 60, Standards of Performance for Industrial-
Commercial-Institutional Steam Generating Units), which already 
requires that natural gas-fired units meet a NOX emissions 
limit of between 0.1 to 0.2 lbs/MMBtu.
Compliance Assurance Requirements
    We proposed compliance provisions for boilers subject to the 
requirements of this section similar to the emissions monitoring 
requirements found in 40 CFR 60.45 (subpart D of 40 CFR part 60, 
Standards of Performance for Fossil-Fuel-Fired Steam Generators). Those 
requirements include, among other provisions, the performance of an 
initial compliance test and installation of a CEMS unless the initial 
performance test indicates the unit's emissions rate is 70 percent or 
less of the emissions limit in this final rule. We received a number of 
comments on this portion of our proposal and provide responses to some 
of these comments in the following paragraphs. Our full responses to 
comments are provided in the response to comments document included in 
the docket for this action.
    Comment: A number of commenters stated that CEMS monitoring is too 
expensive and unnecessary for ensuring compliance with the emissions 
limits for boilers and requested that alternative monitoring techniques 
be allowed.
    Response: The EPA acknowledges that the installation and operation 
of CEMs systems is more expensive than other monitoring techniques and 
may not be necessary for smaller sized boilers that typically produce 
less emissions than larger ones. In response to these comments, we have 
modified the monitoring requirements in the final rule such that 
boilers rated with heat-input capacities less than 250 mmBTU/hr can 
demonstrate compliance by conducting an annual stack test as an 
alternative to monitoring using a CEMs system and by complying with the 
provisions of a monitoring plan meeting specific criteria that enables 
the facility owner or operator to demonstrate continuous compliance 
with the emissions limits of this final rule.
    Comment: One commenter stated that the proposed reporting 
obligations require the submittal of excess emissions reports, 
continuous monitoring, and quarterly emissions reports. The commenter 
suggested that since the NOX emissions standards only apply 
during the ozone season (May 1-September 30), the reporting 
requirements should only apply during the second and third quarters of 
the year and should require that only emissions and monitoring data 
from this time period be included in these reports.
    Response: In response to these comments, the EPA is finalizing 
recordkeeping, monitoring, and reporting requirements that are designed 
to ensure compliance with the applicable emissions limits only during 
the ozone season. Additionally, the final rule requires annual reports 
rather than the proposed quarterly reports as annual reports are 
adequate to determine compliance with the emissions limits during the 
ozone season.
    Comment: A number of commenters stated that some of their boilers 
that may potentially be subject to a final FIP already have a 
NOX CEMS installed and requested that the EPA clarify 
whether a 30-day initial compliance test is required in such cases.
    Response: The EPA's final rule provides that in instances where a 
boiler meeting the applicability requirements of this section has 
already installed a NOX CEMs that meets the requirements for 
such equipment located within 40 CFR 60.13 or 40 CFR part 75, 
Continuous Emissions Monitoring, pursuant to a federally enforceable 
requirement, a 30-day initial compliance test is not required.
    Comment: One commenter stated that Sec.  52.45(d) of the EPA's 
proposed rule included requirements to complete an initial 30-day 
compliance test within 90 days of installing pollution control 
equipment but did not specify whether the test must be complete prior 
to the May 1, 2026, ozone season or by some later date.
    Response: In response to this comment, the EPA is finalizing 
provisions requiring that initial compliance tests occur prior to the 
May 1, 2026 compliance date.
6. Municipal Waste Combustors
Applicability
    The EPA is finalizing regulatory requirements that apply to 
municipal solid waste combustors located in a state subject to the non-
EGU requirements of this final rule (i.e., the 20 states with linkages 
that persist in 2026 as identified in section II.B) and

[[Page 36837]]

that combust greater than or equal to 250 tons per day of municipal 
solid waste (``affected units''). See 40 CFR 52.46(d) for guidelines on 
calculating municipal waste combustor unit capacity. This applicability 
threshold was supported by commenters and is consistent with the 
applicability criteria in 40 CFR part 60, subpart Eb, Standards of 
Performance for New Stationary Sources and Emission Guidelines for 
Existing Sources: Large Municipal Waste Combustors. State RACT rules 
for MWCs and the OTC MWC report similarly define large MWC units as 
units with a combustion capacity greater than or equal to 250 tons per 
day.
    Across the 20 states subject to the non-EGU requirements, this 
applicability threshold captures 28 MWC facilities with a total of 80 
affected units. The identified affected units include mass burn 
waterwall units, mass burn rotary waterwall units, refuse derived fuel 
(RDF) units, and one CLEERGAS\TM\ (``Covanta Low Emissions Energy 
Recovery Gasification'') modular system.\398\ The EPA analyzed actual 
emissions from the facilities captured by this threshold and found that 
on average, a unit with a design capacity of 250 tons per day has a PTE 
of approximately 138 tons per year,\399\ which is similar to the PTE 
threshold applied to other non-EGU sources under this rulemaking.
---------------------------------------------------------------------------

    \398\ See the Final Non-EGU Sectors TSD for additional 
information on this inventory.
    \399\ See the Final Non-EGU Sectors TSD for additional 
information on the calculation of PTE for large MWCs.
---------------------------------------------------------------------------

Emissions Limitations and Rationale
    Based on the available information for this industry, including 
information provided during the public comment period, the OTC MWC 
Report, a review of State and local RACT rules that apply to MWCs, and 
active air permits issued to MWCs, the EPA is finalizing the following 
emissions limits for municipal solid waste combustors.

     Table VI.C.6-1--NOX Emissions Limits for Large Municipal Waste
                               Combustors
------------------------------------------------------------------------
NOX Limit  (ppmvd)  corrected to 7 percent
                  oxygen                          Averaging period
------------------------------------------------------------------------
110.......................................  24-hour.
105.......................................  30-day.
------------------------------------------------------------------------

    At proposal, the EPA noted that the NOX limits for large 
MWCs constructed on or before September 20, 1994 under NSPS 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 large MWCs constructed after September 20, 1994 or for which 
modification or reconstruction is commenced after June 19, 1996 under 
NSPS subpart Eb are found at 40 CFR 60.52b(d) and are 180 ppm during a 
unit's first year of operation and 150 ppm afterwards, applicable 
across all combustor types. These limits correspond to NOX 
emissions rates of 0.31 and 0.26 lb/mmBtu, respectively. In reviewing 
active air permits for MWCs, the EPA found that most MWCs are meeting 
emissions limits similar to those reflected in the applicable 
NSPS.\400\
---------------------------------------------------------------------------

    \400\ For further discussion of the permits reviewed, see the 
Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

    The EPA also cited the OTC's MWC report that evaluated the 
emissions reduction potential of large MWCs located in the OTR from two 
different control levels, one based on a NOX concentration 
of 105 to 110 ppm, and another based on a limit of 130 ppm. The OTC MWC 
report found that a control level of 105 ppmvd on a 30-day rolling 
average basis and a 110 ppmvd on a 24-hour block 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 OTR MWC Report noted that at the 
time of publication, eight MWC units were already subject to permit 
limits of 110 ppm, seven in Virginia, and one in Florida. In 
consideration of control costs, the report cited multiple studies 
evaluating MWCs similar in design to the large MWCs in the OTR and 
found NOX reductions could be achieved at costs ranging from 
$2,900 to $6,600 per ton of NOX reduced.
    To further inform the EPA's consideration of emissions limits for 
MWCs, the EPA requested comment on the emissions limit and averaging 
time MWCs should be required to meet, and specifically whether the EPA 
should adopt emissions rates of 105 ppmvd on a 30-day rolling averaging 
basis and 110 ppmvd on a 24-hour block averaging basis.
    Comment: The agency received several comments regarding emissions 
limits and averaging time for MWCs. Many commenters asserted that the 
EPA should set a 24-hour emissions limit no higher than 110 ppm, noting 
that recent studies have shown that there are a variety of technologies 
that can help a wide range of MWC types achieve this limit at costs 
that are significantly below the $7,500/ton cost effectiveness 
threshold that the EPA identified at proposal. Some commenters 
confirmed the accuracy of the OTC workgroup's estimated cost of 
controls for reducing NOX emissions from MWCs of $2,900 to 
$6,600 while others stated that the cost of controls is well below 
$7,500. One commenter asserted that the EPA should set a 24-hour 
NOX emissions limit of 50 ppmvd for MWCs, which could be 
achieved by the installation of SCR technology. Alternatively, the 
commenters stated that the EPA should set a 24-hour emissions limit no 
higher than 110 ppm based on less effective, though still widely 
available, control technology. Although some commenters stated that 
MWCs should not be included in the rulemaking, no commenters 
specifically identified units or categories of units that could not 
achieve emissions limits of 105 ppmvd on a 30-day rolling averaging 
basis and 110 ppmvd on a 24-hour block averaging basis.
    Response: The EPA recognizes that there have been instances where 
MWCs have installed SCR and achieved emissions rates of 50 ppmvd on a 
24-hr averaging basis and 45 ppmvd on a 30-day rolling averaging basis 
with cost effectiveness estimates around $10,296/ton to $12,779/ton of 
NOX reduced. Given uncertainties pertaining to whether SCR 
can be installed on all types of MWCs, the EPA has decided not to 
establish emissions limits as low as 50 ppmvd for MWCs using SCR at 
this time. However, as generally supported by most commenters, the EPA 
is finalizing emissions limits of 105 ppmvd at 7 percent oxygen 
(O2) on a 30-day rolling average and 110 ppmvd at 7 percent 
O2 on a 24-hour block average that apply at all times except 
during periods of startup and shutdown. The EPA recognizes that the 
final emissions limits for steady-state operations cannot be achieved 
during periods of startup, shutdown, and malfunction. This is primarily 
due to the fact that during periods of startup and shutdown, additional 
ambient air is introduced into the units, resulting in higher oxygen 
concentrations. Therefore, the EPA is finalizing provisions applicable 
during periods of startup and shutdown that do not require correction 
of CEMS data to 7 percent oxygen but do require that such data be 
measured at stack oxygen content. This approach is consistent with EPA 
regulations applicable during startup and shutdown periods for other 
solid-waste incinerators under the NSPS for Commercial and Industrial 
Solid Waste Incineration Units. See 40 CFR part 60, subparts CCCC and 
DDDD.

[[Page 36838]]

    Information received from public commenters generally aligned with 
the results from studies showing that the emissions limits of 105 ppmvd 
on a 30-day rolling averaging basis and 110 ppmvd on a 24-hour block 
averaging basis can be reached using ASNCR or low NOX 
technology in addition to SNCR.\401\ The EPA recognizes that not all 
units can implement low NOX technology, including those 
using Aireal grate technology, those operating RFD units, and those 
with rotary combustor units. Of the 80 affected MWC units that the EPA 
identified, nine units across two facilities are classified as rotary 
combustors, four units at a single facility are classified as RDF, and 
no units captured are classified as using Aireal grate technology. One 
affected unit is classified as CLEERGAS gasification while the 
remaining 64 affected units are classified as mass burn waterwall 
combustors, which have not been explicitly identified as units unable 
to install low NOX technology. For those units unable to 
install low NOX technology or SNCR, the EPA has identified 
ASCNR as an alternative control technology that has been shown to 
enable units to achieve emissions limits of 105 ppmvd on a 30-day 
rolling averaging basis and 110 ppmvd on a 24-hour block averaging 
basis, either as a new retrofit technology or as a significant upgrade 
to existing SNCR. The EPA finds that the availability of ASNCR or SNCR 
and low NOX burners provides sufficient flexibility for MWCs 
to meet the emissions limits in the final rule, especially considering 
74 of the 80 affected units already have SNCR installed. Although there 
is uncertainty on the cost effectiveness of ASNCR for achieving 
significant NOX reductions in small MWCs, small MWCs that 
combust less than 250 tons per day of municipal solid waste are not 
included in this rulemaking.
---------------------------------------------------------------------------

    \401\ The only demonstrated use of low NOX technology 
in addition to SNCR at MWC facilities is at Covanta facilities using 
Covanta's proprietary low NOX combustion system (LN\TM\). 
For the purpose of this rule, EPA is assuming Covanta facilities 
will take advantage of this technology and others will use ASNCR. 
However, other iterations of low NOX technology could 
become available, or facilities could work with Covanta to apply 
this technology to their units.
---------------------------------------------------------------------------

    While commenters noted discrepancies across cost effectiveness 
values for specific types of control technology, no commenters 
specifically indicated that emissions control technology could not be 
cost effectively installed on large MWCs to achieve an emissions limit 
of 105 ppmvd on a 30-day rolling averaging basis and 110 ppmvd on a 24-
hour block averaging basis. Studies show that these limits can be 
achieved through a variety of emissions controls, including ASNCR and 
the addition of low NOX technology to existing SNCR.\402\ Of 
the 80 MWC units subject to this rule, 55 units already have SNCR 
installed, 16 units already have SNCR and low NOX technology 
installed, and three units already have ASNCR installed. Applying the 
cost values provided in the OTC's MWC report to the MWC inventory in 
section 7 of the Final Non-EGU Sectors TSD, the estimated weighted 
average cost effectiveness of applying advanced SNCR to units with and 
without existing SNCR and adding low NOX technology to 
eligible units with SNCR was found to be approximately $7,929.02/
ton.\403\ This value is in line with the control technology costs for 
other non-EGU sectors and the EGU costs associated with this final 
rule.
---------------------------------------------------------------------------

    \402\ See OTC MWC Report at 6-7; Trinity Consultants, Project 
Report Covanta Alexandria/Arlington, Inc., Reasonably Available 
Control Technology Determination for NOX (September 
2017); Trinity Consultants, Project Report Covanta Fairfax, Inc., 
Reasonably Available Control Technology Determination for 
NOX (September 2017); Babcock Power Environmental, Waste 
to Energy NOX Feasibility Study, Prepared for: 
Wheelabrator Technologies Baltimore Waste to Energy Facility 
Baltimore, MD (February 20, 2020); White, M., Goff, S., Deduck, S., 
Gohlke, O., New Process for Achieving Very Low NOX, Proceedings of 
the 17th Annual North American Waste-to-Energy Conference, NAWTEC17 
(May 2009); Letter from the State of New Jersey to Michael Klein, In 
Rreference to Covanta Energy Group, Inc. Essex County Resource 
Recovery Facility, Newark Annual Stack Test Program (March 14, 
2019).
    \403\ See Final Non-EGU Sectors TSD for more information on 
these cost effectiveness estimates were generated.
---------------------------------------------------------------------------

Compliance Assurance Requirements
    In this final rule, the EPA is establishing compliance requirements 
for MWCs similar to the NSPS requirements for large MWCs under 40 CFR 
part 60, subpart Eb. Those requirements include, among other 
provisions, the performance of an initial performance test and 
installation of a CEMS. At proposal, the EPA requested comment on 
whether it would be appropriate to rely on existing testing, 
monitoring, recordkeeping, and reporting requirements for MWCs under 
applicable NSPS or other requirements.
    Comment: Some commenters noted that all large MWCs are already 
required to use CEMS to demonstrate compliance with NOX 
limits under the NSPS program. These commenters asserted that the EPA 
should improve electronic reporting requirements beyond current 
requirements in the NSPS. The commenters suggested that an owner or 
operator of an MWC subject to a limit under the final rule should be 
required to report NOX CEMS data electronically at least 
annually to the EPA's CEDRI and any other database that the EPA will 
utilize when considering revisions to the NSPS for large MWCs. The 
commenters asserted that MWC operators should be required to report 
NOX CEMS data to the EPA's Clean Air Markets database, to 
allow the public access to MWC CEMS data on a large scale for the first 
time.
    Response: The EPA is finalizing provisions that require MWCs 
subject to the requirements of this section to install, calibrate, 
maintain, and operate a CEMS for the measurement of NOX 
emissions discharged into the atmosphere from the affected facility. 
This is consistent with NSPS requirements for large MWCs under 40 CFR 
part 60, subparts Ea and Eb, and state RACT rules that are applicable 
to MWCs in many of the states covered under this rulemaking.\404\ 
Additionally, each emissions unit will be required to conduct an 
initial performance test. With regard to electronic reporting, the 
final rule requires performance tests and reports, including CEMS data, 
to be submitted to CEDRI, as required for all non-EGU industries 
covered by this final rule.
---------------------------------------------------------------------------

    \404\ For examples of RACT provisions applicable to MWCs that 
require CEMS, see Regulations of Connecticut State Agencies section 
22a-174-22e; and Virginia Administrative Code section 5-40-6730, 
subsection (D).
---------------------------------------------------------------------------

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. As discussed in 
this section, states may opt for one of several alternatives that the 
EPA has provided to take over all or portions of the FIP. However, as 
discussed in greater detail further in this section, the EPA also 
recognizes that states retain the discretion to develop SIPs to replace 
a FIP under approaches that differ from those the EPA has finalized.
    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,

[[Page 36839]]

as applicable to that state. Additionally, tribes in Indian country 
within the geographic scope of this 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 
reasonably severable portions of a tribal implementation plan.
    Under the FIPs for the 22 states whose EGUs are required to 
participate in the CSAPR NOX Ozone Season Group 3 Trading 
Program with the modifications finalized in this rule, EPA continues to 
offer ``abbreviated'' and ``full'' SIP options for states. An 
``abbreviated SIP'' allows a state to submit a SIP revision that 
establishes state-determined allowance allocation provisions replacing 
the default FIP allocation provisions but leaving the remaining FIP 
provisions in place. A ``full SIP'' allows a state to adopt a trading 
program meeting certain requirements that 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, states have the option 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).
    Comments: Some commenters alleged that by taking this action, EPA 
is depriving states of the ability to develop SIPs to implement good 
neighbor obligations for the 2015 ozone NAAQS or from choosing their 
own compliance strategies. Commenters also claimed that the EPA cannot 
require states to implement emissions reductions equivalent to the 
emissions control stringency that the EPA determined at Step 3 if their 
proposed SIPs are otherwise shown to be adequate to eliminate 
significant contribution. Other commenters raised concerns that the 
trading program enhancements for EGUs made it too uncertain what a 
state could develop as an approvable replacement SIP. At least one 
commenter argued that the EPA must give states a single, mass-based 
emissions budget so that they can understand how to replace the FIP 
with a SIP.
    Response: The EPA disagrees that it is depriving States of the 
opportunity to replace the FIP with a SIP or preventing states from 
targeting alternative emissions reductions strategies that can be shown 
to be equivalent to the FIP. States have always possessed the authority 
and the opportunity to revise their SIPs at any point. The EPA has 
repeatedly emphasized that states are free to develop a SIP revision to 
replace a transport FIP and submit that to the EPA for approval, and 
this remains true. See 87 FR 20036, 20051 (April 6, 2022); 86 FR 23054, 
23062 (April 30, 2021); 81 FR 74504, 74506 (Oct. 26, 2016). In the FIP 
proposal, as in prior transport actions, the EPA discussed a number of 
ways in which states could take over or replace a FIP, see 87 FR 20036, 
20149-51 (section VII.D: ``Submitting A SIP''); see also id. at 20040 
(noting as one purpose in proposing the FIP that ``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''). The EPA provides further guidance on 
submitting SIPs in this section. If, and when, the EPA receives a SIP 
submission that satisfies the requirements of CAA section 
110(a)(2)(D)(i)(I) and 110(l), the Agency will take action to approve 
those SIP submissions and withdraw the FIP.
    At the outset, we note that the Agency does not anticipate 
revisiting its findings at Steps 1 or 2 of the transport framework. 
Those findings establish that the projected baseline anthropogenic 
emissions from these states contribute to downwind nonattainment or 
maintenance receptors in 2023, and, for certain states, that 
contribution continues through 2026. Those represent critical 
analytical years for downwind areas as they are the last full ozone 
season before the Moderate and Serious area attainment dates. Those 
findings, for those years, establish the basis for an upwind state's 
linkage, from which we proceed to evaluate emissions control 
opportunities and their implementation at Steps 3 and 4.
    We cannot prejudge now whether state submissions to replace the 
EPA's FIP will be approvable, but we note a number of statutory and 
implementation considerations states should be aware of if designing a 
replacement SIP. We have demonstrated that the EPA's transport FIP is 
adequate to eliminate significant contribution to downwind air quality 
problems for purposes of the 2015 ozone NAAQS, and that the FIP does 
not result in overcontrol. The level of reductions required by the FIP 
therefore provides an important benchmark for states in evaluating the 
equivalency of possible replacement SIPs. As discussed in more detail 
in this section, in order to comply with their obligation under CAA 
section 110(a)(2)(D)(i)(I), we generally anticipate that states seeking 
to replace the FIP with a SIP that takes an alternative approach would 
need to establish, at a minimum, an equivalent level of emissions 
reduction to what the FIP requires at Step 3, and any such replacement 
SIP will need to comply with CAA section 110(l).
    The concept of equivalency is important for the state to consider. 
Under CAA section 110(l), ``the Administrator shall not approve a 
revision of a plan if the revision would interfere with any applicable 
requirement concerning attainment . . . or any other applicable 
requirement of this chapter.'' Section 110(l) applies to all CAA 
requirements, including 110(a)(2)(D) requirements relating to 
interstate transport. The EPA interprets section 110(l) such that 
states have two main options to make a noninterference demonstration. 
First, the state could demonstrate that emissions reductions removed 
from the SIP are replaced with new control measures that achieve 
equivalent or greater emissions reductions. Thus, a 110(l) analysis 
would generally need to show that the SIP revision, or, in this case, a 
potential SIP submission replacing an existing FIP, will not interfere 
with any area's ability to continue to attain or maintain the affected 
NAAQS or other CAA requirements. The EPA further has interpreted 
section 110(l) as requiring such substitute measures to be 
quantifiable, permanent, and enforceable, among other considerations. 
For section 110(l) purposes, ``permanent'' means the state cannot 
modify or remove the substitute measure without EPA review and 
approval. Second, the state could conduct air quality modeling or 
develop an attainment or maintenance demonstration based on the EPA's 
most recent technical guidance to show that, even without the control 
measure or with the control measure in its modified form, significant 
contribution from the state would continue to be prohibited as the Act 
requires. As discussed further in this section, for purposes of 
interstate ozone transport, such an analysis entails important 
questions of consistency and equity among states for resolving air 
quality problems that the EPA would need to carefully evaluate.\405\
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    \405\ For instance, future circumstances in which the receptor 
or receptors to which a state is linked come fully into attainment 
or to which the upwind state's linkage drops below 1 percent of the 
NAAQS would likely not, solely on those grounds, be sufficient to 
relax transport requirements established by the FIP or justify 
approving a less stringent SIP. First, the emissions reductions 
achieved by the FIP are part of the reason that a receptor may come 
into attainment or a linkage may drop below 1 percent of the NAAQS. 
Simply removing emissions control requirements the moment this 
occurs is illogical, since those reductions are part of the solution 
by which the attaining air quality was achieved or the linkage was 
resolved. See CAA section 107(d)(3)(E)(iii) (areas cannot be 
redesignated unless based on permanent and enforceable reductions); 
see also Wisconsin, 938 F.3d at 324-25 (explaining that upwind 
states are held to a contribution standard, not a but-for causation 
standard and thus cannot escape good neighbor obligations on the 
basis that other emissions ``cause'' the NAAQS to be exceeded). 
There is a risk of inconsistency and inequity in removing any 
requirements in this manner in that any increase in emissions that 
could occur in one upwind state would likely need to be reviewed in 
relation to the obligations other upwind states would continue to 
meet. Further, any such relaxation in upwind state requirements 
could then unreasonably shift the burden for maintaining air quality 
onto the downwind states where receptors are located. These issues 
may entail complex state- or case-specific analyses that would need 
to be evaluated at the time such a SIP revision is submitted; these 
issues are not ripe for resolution in this action.

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[[Page 36840]]

    In the EPA's experience implementing the CAA criteria pollutant 
program, reductions arising from the good neighbor provision have been 
critically important to the improvement of air quality in downwind 
areas struggling with attainment and maintenance of the NAAQS, and 
states' reliance on good neighbor FIP reductions will need to be taken 
into account in any replacement SIP. In order for a nonattainment area 
to be redesignated to attainment, the CAA requires not only that an 
area attain the standard, but also the Administrator must determine 
``that the improvement in air quality is due to permanent and 
enforceable reductions in emissions resulting from implementation of 
the applicable implementation plan and applicable Federal air pollutant 
control regulations and other permanent and enforceable reductions.'' 
CAA section 107(d)(3)(E)(i) and (iii). Many nonattainment areas across 
the country that have attained various PM2.5 and ozone NAAQS 
have done so in part due to the imposition of Federal good neighbor 
emissions control measures, and, per CAA section 107(d)(3)(E)(iii), 
states have specifically relied on the emissions reductions required by 
those programs in order to be redesignated to attainment. See, e.g., 84 
FR 8422, 8425 (March 8, 2019) (noting that ``[a]t least 140 EPA final 
actions redesignating areas in 20 states to attainment with an ozone 
NAAQS or a fine particulate matter (PM2.5) NAAQS--because 
NOX is a precursor to PM2.5 as well as ozone--
have relied in part on the NOX SIP Call's emissions 
reductions''); see also Sierra Club v. EPA, 774 F.3d 383, 397-99 (7th 
Cir. 2014) (upholding EPA's approval of a redesignation, and 
specifically EPA's determination that reductions from Federal good 
neighbor transport trading programs could reasonably be considered 
``permanent and enforceable'' under the statute); Sierra Club v. EPA, 
793 F.3d 656, 665-68 (6th Cir. 2015) (same). States seeking area 
redesignations are also required under CAA section 107(d)(3)(E)(iv) to 
develop revisions to their state implementation plans that provide for 
maintenance of the NAAQS. In so doing, states develop air quality 
modeling, in which they project future air quality based on emissions 
inputs that account for enforceable emissions reductions, or states 
project emissions in the future relative to emissions in an attainment 
year, showing that the future emissions (which, again, account for on-
the-books, enforceable emissions limits) do not exceed emissions in the 
baseline attainment year. See ``Procedures for Processing Requests to 
Redesignate Areas to Attainment,'' Memo from John Calcagni to EPA 
Regions, September 4, 1992, at 9. Reductions required by Federal good 
neighbor programs may therefore also be relied upon by states seeking 
area redesignations in the context of how states demonstrate that areas 
will maintain the NAAQS.
    We anticipate that air quality in areas struggling to attain and 
maintain the 2015 ozone NAAQS will improve due to the emissions 
reductions required by EPA's FIP. We also anticipate that, consistent 
with EPA's historical experience implementing the NAAQS and acting on 
state requests for nonattainment area redesignations, emissions 
reductions associated with EPA's transport FIP for the 2015 ozone NAAQS 
are likely to be a critical component in those requests for 
redesignation. Where states have relied and are relying on the FIP's 
reductions in order to attain and maintain the NAAQS, EPA will look 
very critically at any replacement SIP that appears to fall short of 
equivalent emissions reductions--in terms of the level of reductions or 
the permanence of those reductions.
    Finally, we disagree with commenters that the absence of fixed, 
mass-based emissions budgets for each state make it impossible to 
replace the FIP with an equivalent SIP. In the case of the trading 
program enhancements for EGUs, the EPA recognizes that the dynamic 
budgeting methodology will generally function to impose a continuous 
incentive on relevant EGUs to continue to implement the emissions 
control strategies determined at Step 3. Further, the backstop rate and 
banking recalibration enhancements also are designed to ensure that 
EGUs implement emissions controls consistent with Step 3 determinations 
on a continuous basis throughout each ozone season. As explained in 
section V.D.4 of this document, these aspects of the trading program do 
not in themselves introduce an overcontrol concern. Nonetheless, 
consistent with the more general principles discussed in this section 
with respect to the potential bases on which states may replace the FIP 
with SIPs, we reserve judgment at this time on whether some future 
demonstration could successfully establish that revision of the FIP or 
its replacement with a SIP could be acceptable even if the way that 
significant contribution is eliminated is through means that differ 
from the trading program enhancements included for EGUs in this action. 
As discussed further in this section, a state may choose to withdraw 
its EGUs from the trading program and instead subject those EGUs to 
daily emissions rates commensurate with installation and optimization 
of state-of-the-art combustion and post-combustion controls as the EPA 
determined at Step 3. Likewise, states are free to explore an 
alternative set of emissions controls on non-EGU industrial sources (or 
other sources in the state), so long as they can demonstrate that an 
equivalent amount of emissions is eliminated. In any case, we need not 
resolve these questions here. The EPA, in promulgating a FIP, is not 
obligated to identify each way a state could replace it with a SIP 
revision. Several options are discussed further in this section, and, 
as always, EPA Regional Offices will work closely with states who wish 
to explore these options or other alternatives.
1. SIP Option To Modify Allocations for 2024 Under EGU Trading Program
    As with the start of past CSAPR rulemakings, the EPA is finalizing 
the option 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. A state 
must submit a letter to EPA by August 4, 2023, 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 September 5, 2023. 
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

[[Page 36841]]

followed by a timely SIP revision that is approved, the approved SIP 
allocations will be recorded by March 1, 2024.
    The EPA received no comments 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 and is finalizing the 
provisions as proposed.
2. SIP Option To Modify Allocations for 2025 and Beyond Under EGU 
Trading Program
    For the 2025 control period and later, 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. 
See 76 FR 48326-48332 for additional discussion of full and abbreviated 
SIP options; see also 40 CFR 52.38(b).
    In this final rule, the EPA is removing the previous regulatory 
text defining specific options for states to expand CSAPR 
NOX Ozone Season Group 3 trading program applicability to 
include EGUs between 15 MWe and 25 MWe or, in the case of states 
subject to the NOX SIP Call, large non-EGU boilers and 
combustion turbines. These options for expanding trading program 
applicability through SIP revisions have been available to states since 
the start of the CSAPR trading programs for small EGUs and since the 
CSAPR Update for large non-EGU boilers and combustion turbines, and no 
state has chosen to use the SIP process for this purpose. Additionally, 
the EPA did not receive comment supporting these expansion options 
during the comment period for this rule. The EPA is finalizing a 
methodology for updating the affected EGU portion of the budget in this 
rule, and the regulatory text defining the applicability expansion to 
non-EGUs did not include a mechanism for updating the incremental non-
EGU portion of a state's budget based on changes over time of the non-
EGU fleet; therefore, continuation of the option to expand 
applicability to certain non-EGUs subject to the NOX SIP 
Call would be inconsistent with the trading program as applied to EGUs 
in this rule.
    However, the EPA recognizes that states may seek to include non-
EGUs covered in this action in an emissions trading program, subject to 
important considerations to ensure equivalency in emissions reductions 
is maintained. While the EPA is not offering specific regulatory text 
to implement an option to expand the trading program applicability, a 
state could submit a SIP to expand the CSAPR NOX Ozone 
Season Group 3 Trading Program applicability, which the EPA would 
evaluate on a case-by-case basis. The SIP revision would need to 
address critical program elements, and include: (1) high-quality 
baseline data, (2) ongoing Part 75 monitoring, and (3) provisions to 
update the non-EGU portion of the budget to appropriately reflect 
changes to the fleet over time.
    For states that want to modify the EPA-determined default 
allocations, the EPA proposed that a state could submit a SIP revision 
that makes changes only to that provision 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. 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 the 
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 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 deadline to submit state-determined 
allocations beginning with the 2025 control period under an approved 
SIP is June 1, 2024, and the deadline for the EPA to record those 
allocations is July 1, 2024. Similarly, a state can 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 EPA recordation of the allocations by July 1, 2025.
    The EPA received no comment on the option to replace certain 
allowance allocation provisions under the Group 3 trading program for 
EGUs for control periods in 2025 and later years through a SIP revision 
and is finalizing the provisions generally as proposed, with the 
exception that any potential expansion of trading program applicability 
under a SIP revision would be evaluated on a case-by-case basis.
3. SIP Option To Replace the Federal EGU Trading Program With an 
Integrated State EGU Trading Program
    For the 2025 control period and later, 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 can submit a SIP revision that makes changes only to modify the 
EPA-determined default allocations and that adopts 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 
previously, 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 chooses to replace 
the 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. Also, for the same reasons discussed with respect to 
the abbreviated SIP option, the EPA is removing the option for states 
to expand CSAPR NOX Ozone Season Group 3 trading program 
applicability to include EGUs between 15 MWe and 25 MWe or, in the case 
of states subject to the NOX SIP Call, large non-EGU boilers 
and combustion turbines.
    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 is December 1, 
2023, the deadline to submit state-determined allocations for the 2025 
control period under an approved SIP is June 1, 2024, and the deadline 
for the EPA to record those allocations is July 1, 2024, and so on.
    The EPA received no comment on the 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 
and is finalizing the provisions generally as proposed, with the 
exception that any potential expansion of trading program applicability 
under a SIP revision would be evaluated on a case-by-case basis.
4. SIP Revisions That Do Not Use the 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

[[Page 36842]]

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. 
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 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 2027 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 background information on considerations for replacing 
a FIP with a SIP, see the discussion in the final CSAPR rulemaking (76 
FR 48326).
5. SIP Revision Requirements for Non-EGU or Industrial Source Control 
Requirements
    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. To 
replace the non-EGU portion of the FIP in a state, the state's SIP must 
provide adequate provisions to prohibit NOX emissions that 
contribute significantly to nonattainment or interfere with maintenance 
of the 2015 ozone NAAQS in any other state. The state SIP submittal 
must demonstrate that the emissions reductions required by the SIP 
would continue to ensure that significant contribution from that state 
has been eliminated through permanent and enforceable measures. 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.
    The most straightforward method for a state to submit a 
presumptively approvable SIP revision to replace the non-EGU portion of 
the FIPs 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 VI.C of this document.
    Comment: One commenter stated that they believed EPA's assertion in 
the proposal that any SIP submittal would have to achieve equal or 
greater reductions for non-EGUs than the FIP was unlawful. The 
commenter asserted that a state's ability to replace the FIP must be 
tied to whether it has addressed the underlying nonattainment/
maintenance concerns by reducing significant contribution from sources 
in the state below the significance threshold, (as opposed to whether 
it prohibits equivalent emissions to the FIP).
    Response: The EPA recognizes that states may select emissions 
reductions strategies that differ from the emissions limitations 
included in the proposed non-EGU FIP; this is discussed in response to 
comments earlier in this section. For example, some states may desire 
to include non-EGUs in a trading program. This may be possible subject 
to taking into account a number of considerations as discussed earlier 
in this section to ensure equivalency between the different approaches. 
But the state must still demonstrate that the replacement SIP provides 
an equivalent or greater amount of emissions reductions as the proposed 
FIP to be presumptively approvable. The EPA anticipates that such 
emissions reductions strategies would have to achieve reductions 
equivalent to or 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 by the 2026 
ozone season.
    EPA further acknowledges that a demonstration of equivalency using 
other control strategies is complicated by the fact that the final 
emissions limits for non-EGU sources are generally unit-specific and 
expressed in a variety of forms; comparative analysis with alternative 
control requirements to determine equivalency would need to take this 
into account. Similarly, we recognize that the emissions trading 
program for EGUs in this action includes a number of enhancements to 
ensure that the Step 3 determination of which emissions are 
``significant'' and must be eliminated continues to be implemented over 
time. Although there is not a fixed, mass-based emissions budget 
established for each state in this action, there are other objective 
metrics that could guide states in developing replacement SIPs. For 
example, for non-EGUs, states may choose to conduct an analysis of 
their industrial stationary sources and present an alternative set of 
emissions limits applying to specific units that it believes would 
achieve an equivalent level of emissions reduction. States could apply 
cost-effectiveness thresholds for emissions control technologies that 
could be applied to establish that some alternative emissions control 
strategy results in equivalent or greater improvement at downwind 
receptors. The EPA anticipates that such a comparison may entail review 
of both baseline emissions information and growth projections between 
the different sets of units to ensure that a truly equivalent or 
greater degree of emissions reduction is achieved; additionality and 
emissions shifting potential may also need to be considered. We note 
that the CAMx policy case run for 2026 provides a benchmark for 
assessing the level of air quality improvement anticipated at receptors 
with implementation of the FIP. This data may be of use to states as 
part of a demonstration that a replacement SIP achieves an equivalent 
or greater level of air quality improvement to the FIP; however, the 
use of such modeling in such a demonstration would need to be more 
fully evaluated at the time of such a SIP revision.
    In all cases, a SIP submitted by a state to replace the non-EGU 
components of the FIPs would very likely 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-

[[Page 36843]]

only'' or ``non-regulatory'' SIPs would very likely be insufficient; 
see discussion in response to comments earlier in this section. 
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.

E. Title V Permitting

    This final 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.\406\ 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'')).
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    \406\ Part 70 addresses requirements for state title V programs, 
and part 71 governs the Federal title V program.
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    The EPA anticipates that, given the nature of the units subject to 
this final rule, most if not all of the sources at which the units are 
located are already subject to title V permitting requirements and 
already possess a title V operating permit. For sources subject to 
title V, the interstate transport requirements for the 2015 ozone NAAQS 
that are applicable to them under the FIPs finalized in this action 
would be ``applicable requirements'' under title V and therefore must 
be addressed in the title V permits. For example, EGU requirements 
concerning designated representatives, monitoring, reporting, and 
recordkeeping, the requirement to hold allowances covering emissions, 
the compliance assurance provisions, and liability, and for non-EGUs, 
the emissions limits and compliance requirements are, to the extent 
relevant to each source, ``applicable requirements'' that must be 
addressed in the permits.
    Consistent with EPA's approach under CSAPR, the CSAPR Update and 
the Revised CSAPR Update, the applicable requirements resulting from 
the 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)), significant 
modifications (40 CFR 70.7(e)(4)) or the standard permit renewal 
provisions (40 CFR 70.7(c) and 71.7(c)).\407\ 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.
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    \407\ 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).
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    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.
1. Title V Permitting Considerations for EGUs
    Title V of the CAA establishes the basic requirements for state 
title V 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 final 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 
those rules would comply with title V and its regulations.\408\ 40 CFR 
97.506(d), 97.806(d) and 97.1006(d). For any new or existing sources 
subject to this rule, identical title V compliance provisions will 
apply with respect to 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 final 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.
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    \408\ 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 final rule would also continue to support the means 
by which a source in the final 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 40 CFR part 75, an excepted monitoring system under appendices D and 
E to 40 CFR part 75, a low mass emissions excepted monitoring 
methodology under 40 CFR 75.19, or an alternative monitoring system 
under subpart E of 40 CFR 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 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.\409\ 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

[[Page 36844]]

governing the use of the title V minor modification procedure.
---------------------------------------------------------------------------

    \409\ Id.
---------------------------------------------------------------------------

    Under CSAPR, the CSAPR Update and the Revised CSAPR Update, 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.\410\ The EPA maintains the same approach for the trading 
program in this final rule.
---------------------------------------------------------------------------

    \410\ https://www.epa.gov/airmarkets/part-75-petition-responses.
---------------------------------------------------------------------------

2. Title V Permitting Considerations for Industrial Stationary Sources
    For non-EGU sources, affected sources will need to work with their 
local, state, or tribal permitting authority to determine if the new 
applicable requirements should be incorporated into their existing 
title V permit under the reopening for cause, significant modification, 
or permit renewal procedures of the approved permitting program. Title 
V permits for existing sources will need to be updated to include the 
applicable requirements of this final rule and any necessary 
preconstruction permits obtained in order to comply with this final 
rule.

F. Relationship to Other Emissions Trading and Ozone Transport Programs

1. NOX SIP Call
    Sources in states affected by both the NOX SIP Call for 
the 1979 ozone NAAQS and the requirements established in this final 
rule for the 2015 ozone NAAQS will be required to comply with the 
requirements of both rules. With respect to EGUs larger than 25 MW, in 
this rule the EPA is requiring NOX ozone season emissions 
reductions from these sources 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. The emissions 
reductions required under this rule are therefore sufficient to satisfy 
the emissions reduction requirements under the NOX SIP Call 
for these large EGUs.
    With respect to the large non-EGU boilers and combustion turbines 
that formerly participated in the NOX Budget Trading Program 
under the NOX SIP Call, the EPA provided options under both 
the CSAPR Update and the Revised CSAPR Update for states to address 
these sources' ongoing NOX SIP Call requirements by 
expanding applicability of the relevant CSAPR trading programs for 
ozone season NOX emissions to include the sources, and no 
state chose to use these options. As discussed in sections VI.D.2 and 
VI.D.3, in this rule the EPA is removing the previous regulatory text 
defining specific options for states to expand trading program 
applicability to include these sources and instead will evaluate any 
SIP revisions seeking to include these sources in the Group 3 trading 
program on a case-by-case basis.\411\
---------------------------------------------------------------------------

    \411\ Only one NOX SIP Call state--Tennessee--
continues to participate in the Group 2 trading program, and the EPA 
has already approved other SIP provisions addressing the ongoing 
NOX SIP Call obligations for Tennessee's large non-EGU 
boilers and combustion turbines. See 84 FR 7998 (March 6, 2019); 86 
FR 12092 (March 2, 2021).
---------------------------------------------------------------------------

2. Acid Rain Program
    This rule does not affect any SO2 and NOX 
requirements under the Acid Rain Program, which are established 
separately under 40 CFR parts 72 through 78 and will continue to apply 
independently of this rule's provisions. Sources subject to the Acid 
Rain Program will continue to be required to comply with all 
requirements of that program, including the requirement to hold 
sufficient allowances issued under the Acid Rain Program to cover their 
SO2 emissions after the end of each control period.
3. Other CSAPR Trading Programs
    This rule does 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. Sources subject to any 
of the CSAPR trading programs will continue to be required to comply 
with all requirements of all such trading programs to which they are 
subject, including the requirement to hold sufficient allowances issued 
under the respective programs to cover emissions after the end of each 
control period.
    The EPA also notes that where a state's good neighbor obligations 
with respect to the 1997 ozone NAAQS or the 2008 ozone NAAQS have 
previously been met by participation of the state's large EGUs in the 
CSAPR NOX Ozone Season Group 2 Trading Program (or earlier 
by the CSAPR NOX Ozone Season Group 1 Trading Program), the 
EPA will deem those obligations to be satisfied by the participation of 
the same sources in the CSAPR NOX Ozone Season Group 3 
Trading Program. Specifically, for all states covered by the Group 3 
trading program under this rule except Minnesota, Nevada, and Utah, 
participation of the state's EGUs in the Group 3 trading program will 
be deemed to satisfy not only the EGU-related portion of the state's 
good neighbor obligations with respect to the 2015 ozone NAAQS but also 
the state's good neighbor obligations with respect to the 2008 ozone 
NAAQS. In addition, for Alabama, Arkansas, Illinois, Indiana, Kentucky, 
Louisiana, Michigan, Mississippi, Missouri, Oklahoma, and Wisconsin, 
participation of the state's EGUs in the Group 3 trading program will 
also be deemed to satisfy the state's good neighbor obligations with 
respect to the 1997 ozone NAAQS.\412\
---------------------------------------------------------------------------

    \412\ For the remaining state transitioning from the Group 2 
trading program to the Group 3 trading program under this rule--
Texas--as well as the remaining states that transitioned from the 
Group 2 trading program to the Group 3 trading program under the 
Revised CSAPR Update--Maryland, New Jersey, New York, Ohio, 
Pennsylvania, Virginia, and West Virginia--participation of the 
states' EGUs in the Group 2 trading program as required by the CSAPR 
Update was addressing good neighbor obligations of the states with 
respect to only the 2008 ozone NAAQS, not the 1997 ozone NAAQS. See 
81 FR 74523-74526.
---------------------------------------------------------------------------

VII. 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 final 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 X.J of this 
final rule and analytical results are available in Chapter 7 of the 
RIA. This analysis is being provided for informational purposes only.

A. Introduction

    Executive Order 12898 directs EPA 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.\413\ Additionally, Executive

[[Page 36845]]

Order 13985 is intended to advance racial equity and support 
underserved communities through Federal Government actions.\414\ 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. The EPA 
further defines the term fair treatment to mean that ``no group of 
people should bear a disproportionate burden of environmental harms and 
risks, including those resulting from the negative environmental 
consequences of industrial, governmental, and commercial operations or 
programs and policies.'' \415\ In recognizing that minority and low-
income populations often bear an unequal burden of environmental harms 
and risks, the EPA continues to consider ways of protecting them from 
adverse public health and environmental effects of air pollution.
---------------------------------------------------------------------------

    \413\ 59 FR 7629, February 16, 1994.
    \414\ 86 FR 7009, January 20, 2021.
    \415\ https://www.epa.gov/environmentaljustice.
---------------------------------------------------------------------------

B. Analytical Considerations

    The EPA's environmental justice (EJ) technical guidance \416\ 
states that:
---------------------------------------------------------------------------

    \416\ U.S. Environmental Protection Agency (EPA), 2015. Guidance 
on Considering Environmental Justice During the Development of 
Regulatory Actions.

    The analysis of potential EJ concerns for regulatory actions 
should address three questions:
    1. Are there potential EJ concerns associated with environmental 
stressors affected by the regulatory action for population groups of 
concern in the baseline?
    2. Are there potential EJ 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 EJ concerns created or mitigated compared to the baseline?

    To address these questions in the 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 
final 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., residence of 
historically red lined areas), environmental impacts (e.g., other ozone 
metrics), and more granular spatial resolutions (e.g., neighborhood 
scale) that were not evaluated.
    For the final rule, we employ two types of analytics to respond to 
the previous 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).\417\ 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, several caveats 
should be noted. For example, the air pollutant exposure metrics are 
limited to those used in the benefits assessment. For ozone, that is 
the maximum daily 8-hour average, averaged across the April through 
September warm season (AS-MO3) and for PM2.5 that is the 
annual average. This ozone metric likely smooths potential daily ozone 
gradients and is not directly relatable to the National Ambient Air 
Quality Standard (NAAQS), whereas the PM2.5 metric is more 
similar to the long term PM2.5 standard. The air quality 
modeling estimates are also based on state level emissions data paired 
with facility-level baseline emissions, and provided at a resolution of 
12km\2\. Additionally, here we focus on air quality changes due to this 
final rulemaking and infer post-policy exposure burden impacts.
---------------------------------------------------------------------------

    \417\ 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).
---------------------------------------------------------------------------

    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 information about ozone concentration changes experienced by 
everyone within each population.
    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); and (2) the potential for disproportionate 
ozone and PM2.5 concentrations in the baseline and 
concentration changes after rule implementation across different 
demographic groups (section 7.4). 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 final rule. 
However, such analyses are less useful here as they do not account for 
the potential impacts of this final rule on long-range concentration 
changes. Baseline demographic proximity analysis presented in the RIA 
suggest that larger percentages of Hispanics, African Americans, people 
below the poverty level, people with less educational attainment, and 
people linguistically isolated are living within 5 km and 10 km of an 
affected EGU, compared to national averages. It also finds larger 
percentages of African Americans, people below the poverty level, and 
with less educational attainment living within 5 km and 10 km of an 
affected non-EGU facility. Relating these results to question 1 from 
section 7.2 of the RIA, we conclude that there may be potential EJ 
concerns associated with directly emitted pollutants that are affected 
by the regulatory action (e.g., NO2) for certain population 
groups of concern in the baseline. However, as proximity to affected 
facilities does not capture variation in baseline exposure across 
communities, nor does it indicate that any exposures or impacts will 
occur, these results do not in themselves demonstrate disproportionate 
impacts of affected facilities in the baseline and should not be 
interpreted as a direct measure of exposure or impact.
    Whereas proximity analyses are limited to evaluating the 
representativeness of populations residing nearby affected facilities, 
the ozone and PM2.5 exposure analyses can provide insight 
into all three EJ questions. Even though both the proximity and 
exposure analyses can potentially 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.
    The baseline analysis of ozone and PM2.5 concentration 
burden 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 ozone and PM2.5 analyses show 
that certain populations, such as Hispanics, Asians, those 
linguistically isolated, those less

[[Page 36846]]

educated, and children may experience somewhat higher ozone and 
PM2.5 concentrations compared to the national average. 
Therefore, also in response to question 1, there likely are potential 
environmental justice concerns associated with ozone and 
PM2.5 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. In addition, we 
infer that disparities in the ozone and PM2.5 concentration 
burdens are likely to persist after implementation of the regulatory 
action or alternatives under consideration due to similar modeled 
concentration reductions across population demographics (question 2).
    Question 3 asks whether potential EJ concerns will be created or 
mitigated as compared to the baseline. Due to the very small 
differences observed in the distributional analyses of post-policy 
ozone and PM2.5 exposure impacts across populations, we do 
not find evidence that potential EJ concerns related to ozone and 
PM2.5 concentrations will be created or mitigated as 
compared to the baseline.\418\
---------------------------------------------------------------------------

    \418\ Please note, exposure results should not be extrapolated 
to other air pollutant. Detailed environmental justice analytical 
results can be found in Chapter 7 of the RIA.
---------------------------------------------------------------------------

C. Outreach and Engagement

    Prior to proposal, the EPA hosted an outreach webinar with 
environmental justice stakeholders to share information about the 
proposed rule and solicit feedback about potential environmental 
justice considerations. The webinar was attended by representatives of 
state governments, federally recognized tribes, environmental NGOs, 
higher education institutions, industry, and the EPA.\419\ Participants 
were invited to comment on pre-proposal environmental justice 
considerations during the webinar or submit written comments to a pre-
proposal non-regulatory docket.
---------------------------------------------------------------------------

    \419\ This does not constitute EPA's tribal consultation under 
E.O. 13175, which is described in section XI.F of this rule.
---------------------------------------------------------------------------

    After proposal, the EPA opened a public comment period to invite 
the public to submit written comments to the regulatory docket for this 
rulemaking.\420\ The EPA also invited the public to participate in a 
public hearing held on April 21, 2022. A transcript of the public 
hearing is available in the docket for this rulemaking. Additionally, 
on March 31, 2022, the EPA hosted an informational webinar with non-
governmental groups and environmental justice stakeholders to answer 
questions and share information about the proposed rule. A record of 
this webinar, including the informational power point shared at the 
webinar is available in the docket for this rulemaking.
---------------------------------------------------------------------------

    \420\ Comments and responses regarding environmental justice 
considerations are available in Section 6 of the RTC document for 
this rulemaking.
---------------------------------------------------------------------------

VIII. Costs, Benefits, and Other Impacts of the Final Rule

    In the RIA for the Federal Good Neighbor Plan Addressing Regional 
Ozone Transport for the 2015 Ozone National Ambient Air Quality 
Standards, the EPA estimated the health and climate benefits, 
compliance costs, and emissions changes that may result from the final 
rule for the analysis period 2023 to 2042. The estimated health and 
climate benefits and compliance costs are presented in detail in this 
RIA. The EPA notes that for EGUs the estimated benefits and compliance 
costs are directly associated with fully operating existing SCRs during 
ozone season; fully operating existing SNCRs during ozone season; 
installing state-of-the-art combustion controls; imposing a backstop 
emissions rate on certain units that lack SCR controls; and installing 
SCR and SNCR post-combustion controls. The EPA also notes that for non-
EGUs the estimated health benefits and compliance costs are directly 
associated with installing controls to meet the NOX 
emissions requirements presented in section I.B of this document.
    For EGUs, the EPA analyzed this action's emissions 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. The EPA also analyzed a more and a less stringent 
alternative. The more and less stringent alternatives differ from the 
rule in that they set different NOX ozone season emissions 
budgets for the affected EGUs and different dates for large, coal-fired 
EGUs' compliance with the backstop emissions rate.
    For non-EGUs, the EPA developed an analytical framework to 
determine which industries and emissions unit types to include in a 
proposed Transport FIP for the 2015 ozone NAAQS transport obligations. 
A February 28, 2022 memorandum, titled ``Screening Assessment of 
Potential Emissions Reductions, Air Quality Impacts, and Costs from 
Non-EGU Emissions Units for 2026,'' documents the analytical framework 
used to identify industries and emissions unit types included in the 
proposed FIP. To further evaluate the industries and emissions unit 
types identified and to establish the proposed emissions limits, the 
EPA reviewed Reasonably RACT rules, NSPS rules, NESHAP rules, existing 
technical studies, rules in approved SIP submittals, consent decrees, 
and permit limits. That evaluation is detailed in the Proposed Non-EGU 
Sectors TSD prepared for the proposed FIP. The EPA is retaining the 
industries and many of the emissions unit types included in the 
proposal in this final action. For the non-EGU industries, in the final 
rule we made some minor changes to the non-EGU emissions units covered, 
the applicability criteria, as well as provided for facility-wide 
emissions averaging for engines and for a low-use exemption to 
eliminate the need to install controls on low-use boilers.
    Table VIII-1 provides the projected 2023 through 2027, 2030, 2035, 
and 2042 EGU NOX, SO2, PM2.5, and CO2 
emissions 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 VIII-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
                                                                Final rule       alternative       alternative
----------------------------------------------------------------------------------------------------------------
2023:
    NOX (ozone season).....................................           10,000            10,000            10,000
    NOX (annual)...........................................           15,000            15,000            15,000
    SO2 (annual)...........................................            1,000             3,000             1,000
    CO2 (annual, thousand metric tons).....................  ...............  ................  ................

[[Page 36847]]

 
    PM2.5 (annual).........................................  ...............  ................  ................
2024:
    NOX (ozone season).....................................           21,000            10,000            33,000
    NOX (annual)...........................................           25,000            15,000            57,000
    SO2 (annual)...........................................           19,000             5,000            59,000
    CO2 (annual, thousand metric tons).....................           10,000             4,000            20,000
    PM2.5 (annual).........................................            1,000  ................             1,000
2025:
    NOX (ozone season).....................................           32,000            10,000            56,000
    NOX (annual)...........................................           35,000            15,000            99,000
    SO2 (annual)...........................................           38,000             7,000           118,000
    CO2 (annual, thousand metric tons).....................           21,000             8,000            40,000
    PM2.5 (annual).........................................            2,000             1,000             2,000
2026:
    NOX (ozone season).....................................           25,000             8,000            49,000
    NOX (annual)...........................................           29,000            12,000            88,000
    SO2 (annual)...........................................           29,000             5,000           104,000
    CO2 (annual, thousand metric tons).....................           16,000             6,000            34,000
    PM2.5 (annual).........................................            1,000  ................             2,000
2027:
    NOX (ozone season).....................................           19,000             6,000            43,000
    NOX (annual)...........................................           22,000             9,000            78,000
    SO2 (annual)...........................................           21,000             4,000            91,000
    CO2 (annual, thousand metric tons).....................           10,000             3,000            28,000
    PM2.5 (annual).........................................            1,000  ................             2,000
2030:
    NOX (ozone season).....................................           34,000            33,000            31,000
    NOX (annual)...........................................           62,000            59,000            50,000
    SO2 (annual)...........................................           93,000            98,000            51,000
    CO2 (annual, thousand metric tons).....................           26,000            23,000             8,000
    PM2.5 (annual).........................................            1,000             1,000  ................
2035:
    NOX (ozone season).....................................           29,000            30,000            27,000
    NOX (annual)...........................................           46,000            46,000            41,000
    SO2 (annual)...........................................           21,000            19,000            15,000
    CO2 (annual, thousand metric tons).....................           16,000            15,000             8,000
    PM2.5 (annual).........................................            1,000             1,000  ................
2042:
    NOX (ozone season).....................................           22,000            22,000            22,000
    NOX (annual)...........................................           23,000            22,000            21,000
    SO2 (annual)...........................................           15,000            15,000             7,000
    CO2 (annual, thousand metric tons).....................            9,000             8,000             4,000
    PM2.5 (annual).........................................
----------------------------------------------------------------------------------------------------------------
Emissions changes for NOX, SO2, and PM2.5 are in tons.

    Table VIII-2 provides a summary of the ozone season NOX 
emissions for non-EGUs for the 20 states subject to the non-EGU 
emissions requirements starting in 2026, along with the estimated ozone 
season NOX reductions for 2026 for the 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 VIII-2--Ozone Season NOX Emissions and Emissions Reductions (Tons) for Non-EGUs for the Final Rule and the
                                      Less and More Stringent Alternatives
----------------------------------------------------------------------------------------------------------------
                                                              Final rule--    Less stringent--  More stringent--
                                             2019 Ozone     ozone season NOX  ozone season NOX  ozone season NOX
                  State                   season emissions     reductions        reductions        reductions
                                                 \a\
----------------------------------------------------------------------------------------------------------------
AR......................................             8,790             1,546               457             1,690
CA......................................            16,562             1,600             1,432             4,346
IL......................................            15,821             2,311               751             2,991
IN......................................            16,673             1,976             1,352             3,428
KY......................................            10,134             2,665               583             3,120
LA......................................            40,954             7,142             1,869             7,687
MD......................................             2,818               157               147             1,145
MI......................................            20,576             2,985               760             5,087
MO......................................            11,237             2,065               579             4,716
MS......................................             9,763             2,499               507             2,650

[[Page 36848]]

 
NJ......................................             2,078               242               242               258
NV \421\................................             2,544                 0                 0                 0
NY......................................             5,363               958               726             1,447
OH......................................            18,000             3,105             1,031             4,006
OK......................................            26,786             4,388             1,376             5,276
PA......................................            14,919             2,184             1,656             4,550
TX......................................            61,099             4,691             1,880             9,963
UT......................................             4,232               252                52               615
VA......................................             7,757             2,200               978             2,652
WV......................................             6,318             1,649               408             2,100
                                         -----------------------------------------------------------------------
    Totals..............................           302,425            44,616            16,786            67,728
----------------------------------------------------------------------------------------------------------------
\a\ The 2019 ozone season emissions are calculated as 5/12 of the annual emissions from the following two
  emissions inventory files: nonegu_SmokeFlatFile_2019NEI_POINT_20210721_controlupdate_13sep2021_v0 and
  oilgas_SmokeFlatFile_2019NEI_POINT_20210721_controlupdate_13sep2021_v0.

    For EGUs, the EPA analyzed ozone season NOX emissions 
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 prepared an assessment summarized in the memorandum 
titled Summary of Final Rule Applicability Criteria and Emissions 
Limits for Non-EGU Emissions Units, Assumed Control Technologies for 
Meeting the Final Emissions Limits, and Estimated Emissions Units, 
Emissions Reductions, and Costs, and the memorandum includes estimated 
emissions reductions by state for the rule.\421\
---------------------------------------------------------------------------

    \421\ We are not aware of existing non-EGU emissions units in 
Nevada that meet the applicability criteria for non-EGUs in the 
final rule. If any such units in fact exist, they would be subject 
to the requirements of the rule just as in any other state. In 
addition, any new emissions unit in Nevada that meets the 
applicability criteria in the final rule will be subject to the 
final rule's requirements. See section III.B.1.d.
---------------------------------------------------------------------------

    Table VIII-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 requirements for non-
EGUs. The costs presented in Table VIII-3 do not include monitoring and 
reporting costs, which EPA summarizes in section X.B.2 of this 
document. The monitoring and reporting costs presented in section X.B.2 
are $0.35 million per year for EGUs and $3.8 million per year for non-
EGUs. For EGUs, compliance costs are negative in 2026. 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.\422\ 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 the memorandum titled Summary of Final Rule 
Applicability Criteria and Emissions Limits for Non-EGU Emissions 
Units, Assumed Control Technologies for Meeting the Final Emissions 
Limits, and Estimated Emissions Units, Emissions Reductions, and Costs, 
see Chapter 4, sections 4.4 and 4.5.4 of the RIA.
---------------------------------------------------------------------------

    \422\ As a sensitivity, the EPA re-calculated costs assuming 
annual costs cannot be negative. This resulted in annualized 2023-42 
costs under the final rule increasing from $448.6 million to $449.5 
million (less than 1%) and did not change the conclusions of the 
RIA. See Section 4.5.2 of the RIA for more information.

                    Table VIII-3--Total Estimated Compliance Costs (Million 2016$), 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                               Less-stringent    More-stringent
                                                                Final rule       alternative       alternative
----------------------------------------------------------------------------------------------------------------
2023:
    EGUs...................................................               57                56                49
    Non-EGUs...............................................  ...............  ................  ................
----------------------------------------------------------------------------------------------------------------
    Total..................................................               57                56                49
2024:
    EGUs...................................................              (5)              (35)               840
    Non-EGUs...............................................  ...............  ................  ................
----------------------------------------------------------------------------------------------------------------
    Total..................................................              (5)              (35)               840
2025:
    EGUs...................................................              (5)              (35)               840
    Non-EGUs...............................................  ...............  ................  ................
----------------------------------------------------------------------------------------------------------------
    Total..................................................              (5)              (35)               840
2026:

[[Page 36849]]

 
    EGUs...................................................              (5)              (35)               840
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................              570               110             2,100
2027:
    EGUs...................................................               24              (47)               760
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................              600                97             2,000
2028:
    EGUs...................................................               24              (47)               760
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................              600                97             2,000
2029:
    EGUs...................................................               24              (47)               760
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................              600                97             2,000
2030:
    EGUs...................................................              710               770               840
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,300               920             2,100
2031:
    EGUs...................................................              710               770               840
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,300               920             2,100
2032:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2033:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2034:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2035:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2036:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2037:
    EGUs...................................................              820               850               590
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               990             1,900
2038:
    EGUs...................................................              820               830               600
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               970             1,900
2039:
    EGUs...................................................              820               830               600
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               970             1,900
2040:
    EGUs...................................................              820               830               600

[[Page 36850]]

 
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               970             1,900
2041:
    EGUs...................................................              820               830               600
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               970             1,900
2042:
    EGUs...................................................              820               830               600
    Non-EGUs...............................................              570               140             1,300
----------------------------------------------------------------------------------------------------------------
    Total..................................................            1,400               970             1,900
----------------------------------------------------------------------------------------------------------------

    Tables VIII-4 and VIII-5 report the estimated economic value of 
avoided premature deaths and illness in each year relative to the 
baseline along with the 95 percent confidence interval. In each of 
these tables, for each discount rate and regulatory control 
alternative, two 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 VIII-4--Estimated Discounted Economic Value of Avoided Ozone-Related Premature Mortality and Illness for
                       the Final Rule and the Less and More Stringent Alternatives in 2023
                           [95 Percent confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                            Less stringent      More stringent
      Disc rate                 Pollutant                Final rule          alternative          alternative
----------------------------------------------------------------------------------------------------------------
3%..................  Ozone Benefits..............  $100 [$27 to $220]   $100 [$27 to $220]   $110 [$28 to $230]
                                                     \c\ and $820 [$91    \c\ and $810 [$91    \c\ and $840 [$94
                                                     to $2,100] \d\.      to $2,100] \d\.      to $2,200] \d\.
7%..................  Ozone Benefits..............  $93 [$17 to 210]     $93 [$17 to $210]    $96 [$18 to $210]
                                                     \c\ and $730 [$75    \c\ and $730 [$75    \c\ and $750 [$77
                                                     to $1,900] \d\.      to $1,900] \d\.      to $2,000] \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 ozone benefits for changes in NOX for the ozone season. This table does not include benefits
  from reductions for non-EGUs because reductions from these sources are not expected prior to 2026 when the
  final standards would apply to these sources.
\c\ Using the pooled short-term ozone exposure mortality risk estimate.
\d\ Using the long-term ozone exposure mortality risk estimate.


  Table VIII-5--Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Related Premature Mortality and
                 Illness for the Final Rule and the Less and More Stringent Alternatives in 2026
                              [95% Confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                            Less stringent      More stringent
      Disc rate                 Pollutant                Final rule          alternative          alternative
----------------------------------------------------------------------------------------------------------------
3%..................  Ozone Benefits..............  $1,100 [$280 to      $420 [$110 to $900]  $1,900 [470 to
                                                     $2,400] \c\ and      \c\ and $3,400       $4,000] \c\ and
                                                     $9,400 [$1,000 to    [$380 to $8,900]     $15,000 [$1,700
                                                     $25,000] \ d\.       \d\.                 to $40,000] \d\.
                      PM Benefits.................  $2,000 [$220 to      $530 [$57 to         $6,400 [$690 to
                                                     $5,300] and $4,400   $1,400] and $1,100   $17,000] and
                                                     [$430 to $12,000].   [$110 to $3,100].    $14,000 [$1,300
                                                                                               to $37,000]
                      Ozone plus PM Benefits......  $3,200 [$500 to      $950 [$160 to        $8,300 [$1,200 to
                                                     $7,700] \c\ and      $2,300] \c\ and      $21,000] \c\ and
                                                     $14,000 [$1,500 to   $4,600 [$490 to      $29,000 [$3,000
                                                     $36,000] \d\.        $12,000] \d\.        to $77,000] \d\.
7%..................  Ozone Benefits..............  $1,000 [$180 to      $380 [$68 to $850]   $1,700 [$300 to
                                                     $2,300] \c\ and      \c\ and $3,100       $3,800] \c\ and
                                                     $8,400 [$850 to      [$310 to $8,100]     $14,000 [$1,400
                                                     $22,000] \d\.        \d\.                 to $36,000] \ d\.
                      PM Benefits.................  $1,800 [$190 to      470 [$50 to $1,200]  $5,800 [$600 to
                                                     $4,700] and $3,900   and $1,000 [$100     $15,000] and
                                                     [$380 to $11,000].   to $2,800].          $12,000 [$1,200
                                                                                               to $33,000].
                      Ozone plus PM Benefits......  $2,800 [$370 to      $850 [$120 to        $7,500 [$910 to
                                                     $7,000] \c\ and      $2,100] \c\ and      $19,000] \c\ and
                                                     $12,000 [$1,200 to   $4,100 [$410 to      $26,000 [$2,600
                                                     $33,000] \d\.        $11,000] \d\.        to $69,000] \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 annual changes in PM2.5 and PM2.5 precursors in 2026.
\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 VIII-6, VIII-7, and VIII-8, the EPA presents a summary of 
the monetized health and climate benefits, costs, and net benefits of 
the rule and the more and less stringent alternatives for 2023, 2026, 
and 2030, respectively. There are important water quality benefits and 
health benefits associated with reductions in concentrations of air 
pollutants other than ozone and PM2.5 that are not 
quantified. Discussion of the non-monetized health, welfare, and water 
quality benefits is found in Chapter 5 of the RIA. In this action, 
monetized climate benefits are presented for purposes of providing a 
complete economic impact analysis under E.O. 12866 and other relevant 
Executive orders. The estimates of GHG emissions changes and the 
monetized benefits associated with those changes

[[Page 36851]]

is not part of the record basis for this action, which is taken to 
implement the good neighbor provision, CAA section 110(a)(2)(D)(i)(I), 
for the 2015 ozone NAAQS.

     Table VIII-6--Monetized Benefits, Costs, and Net Benefits of the Final Rule and Less and More Stringent
                                       Alternatives for 2023 for the U.S.
                           [3% Discount rate for benefits, millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                              Final rule              alternative              alternative
----------------------------------------------------------------------------------------------------------------
Health Benefits \c\..................  $100 and $820..........  $100 and $810..........  $110 and $840.
Climate Benefits.....................  $5.....................  $4.....................  $5.
Total Benefits.......................  $100 and $820..........  $100 and $820..........  $110 and $840.
Costs \d\............................  $57....................  $56....................  $49.
Net Benefits.........................  $48 and $760...........  $48 and $760...........  $66 and $800.
----------------------------------------------------------------------------------------------------------------
\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.
\c\ The health benefits are associated with two point estimates from two different epidemiologic studies. For
  the purposes of presenting the values in this table the health and climate benefits are discounted at 3
  percent.
\d\ The costs presented in this table are 2023 annual estimates for each alternative analyzed. For EGUs, an NPV
  of costs was calculated using a 3.76 percent real discount rate consistent with the rate used in IPM's
  objective function for cost-minimization. For further information on the discount rate use, please see Chapter
  4, Table 4-8 in the RIA.


     Table VIII-7--Monetized Benefits, Costs, and Net Benefits of the Final Rule and Less and More Stringent
                                       Alternatives for 2026 for the U.S.
                           [3% Discount rate for benefits, millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                              Final rule              alternative              alternative
----------------------------------------------------------------------------------------------------------------
Health Benefits \c\..................  $3,200 and $14,000.....  $950 and $4,600........  $8,300 and $29,000.
Climate Benefits.....................  $1,100.................  $420...................  $2,100.
Total Benefits.......................  $4,300 and $15,000.....  $1,400 and $5,000......  $10,000 and $31,000.
Costs \d\............................  $570...................  $110...................  $2,100.
Net Benefits.........................  $3,700 and $14,000.....  $1,300 and $4,900......  $8,300 and $29,000.
----------------------------------------------------------------------------------------------------------------
\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\ The health benefits are associated with two point estimates from two different epidemiologic studies. For
  the purposes of presenting the values in this table the health and climate benefits are discounted at 3
  percent.
\d\ The costs presented in this table are 2026 annual estimates for each alternative analyzed. For EGUs, an NPV
  of costs was calculated using a 3.76 percent real discount rate consistent with the rate used in IPM's
  objective function for cost-minimization. For further information on the discount rate use, please see Chapter
  4, Table 4-8 in the RIA.


     Table VIII-8--Monetized Benefits, Costs, and Net Benefits of the Final Rule and Less and More Stringent
                                       Alternatives for 2030 for the U.S.
                           [3% Discount rate for benefits, millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                              Final rule              alternative              alternative
----------------------------------------------------------------------------------------------------------------
Health Benefits \c\..................  $3,400 and $15,000.....  $1,000 and $4,900......  $9,000 and $31,000.
Climate Benefits.....................  $1,500.................  $1,300.................  $500.
Total Benefits.......................  $4,900 and $16,000.....  $2,300 and $6,200......  $9,500 and $31,000.
Costs \d\............................  $1,300.................  $920...................  $2,100.
Net Benefits.........................  $3,600 and $15,000.....  $1,400 and $5,300......  $7,400 and $29,000.
----------------------------------------------------------------------------------------------------------------
\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\ The health benefits are associated with two point estimates from two different epidemiologic studies. For
  the purposes of presenting the values in this table the health and climate benefits are discounted at 3
  percent.
\d\ The costs presented in this table are 2030 annual estimates for each alternative analyzed. For EGUs, an NPV
  of costs was calculated using a 3.76 percent real discount rate consistent with the rate used in IPM's
  objective function for cost-minimization. For further information on the discount rate use, please see Chapter
  4, Table 4-8 in the RIA.

    In addition, Table VIII-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 recommended by OMB's Circular A-4 and are 
presented in 2016 dollars discounted to 2023.

[[Page 36852]]



 Table VIII-9--Monetized Estimated Health and Climate Benefits, Compliance Costs, and Net Benefits of the Final
                        Rule and Less and More Stringent Alternatives, 2023 Through 2042
                                      [Millions 2016$, discounted to 2023]
----------------------------------------------------------------------------------------------------------------
                                                      3 Percent discount rate         7 Percent discount rate
                                                 ---------------------------------------------------------------
                                                        PV              EAV             PV              EAV
----------------------------------------------------------------------------------------------------------------
                                                 Health benefits
----------------------------------------------------------------------------------------------------------------
Final Rule......................................        $200,000         $13,000        $130,000         $12,000
Less Stringent Alternative......................          67,000           4,500          40,000           3,800
More Stringent Alternative......................         410,000          28,000         240,000          23,000
----------------------------------------------------------------------------------------------------------------
                                              Climate Benefits \a\
----------------------------------------------------------------------------------------------------------------
Final Rule......................................          15,000             970          15,000             970
Less Stringent Alternative......................          11,000             770          11,000             770
More Stringent Alternative......................          14,000             920          14,000             920
----------------------------------------------------------------------------------------------------------------
                                                Compliance Costs
----------------------------------------------------------------------------------------------------------------
Final Rule......................................          14,000             910           9,400             770
Less Stringent Alternative......................           8,700             590           5,300             500
More Stringent Alternative......................          25,000           1,700          17,000           1,600
----------------------------------------------------------------------------------------------------------------
                                                  Net Benefits
----------------------------------------------------------------------------------------------------------------
Final Rule......................................         200,000          13,000         140,000          12,000
Less Stringent Alternative......................          70,000           4,700          42,000           4,000
More Stringent Alternative......................         400,000          27,000         240,000          22,000
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2) (model
  average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate).
  For presentational purposes in this table, the climate benefits associated with the average SC-CO2 at a 3-
  percent discount rate are used in the columns displaying results of other costs and benefits that are
  discounted at either a 3-percent or 7-percent discount rate.

    As shown in Table VIII-9, the PV of the monetized health benefits 
of this rule, discounted at a 3-percent discount rate, is estimated to 
be about $200 billion ($200,000 million), with an EAV of about $13 
billion ($13,000 million). At a 7-percent discount rate, the PV of the 
monetized health benefits is estimated to be $130 billion ($130,000 
million), with an EAV of about $12 billion ($12,000 million). The PV of 
the monetized climate benefits of this rule, discounted at a 3-percent 
discount rate, is estimated to be about $15 billion ($15,000 million), 
with an EAV of about $970 million. The PV of the monetized compliance 
costs, discounted at a 3-percent rate, is estimated to be about $14 
billion ($14,000 million), with an EAV of about $910 million. At a 7-
percent discount rate, the PV of the compliance costs is estimated to 
be about $9.4 billion ($9,400 million), with an EAV of about $770 
million.
    In addition to the analysis of costs and benefits as described 
above, for the final rule, the EPA was able to conduct a full-scale 
photochemical grid modeling run of the effects of the ``final rule'' 
emissions control scenario in 2026. This modeling can be used to 
estimate the impacts on projected 2026 ozone design values that are 
expected from the combined EGU and non-EGU control emissions reductions 
in this final rule. These results do not replace the AQAT-generated 
estimates used for our Step 3 determinations, and the EPA needed to 
continue to use AQAT for Step 3 determinations in order to characterize 
various potential control scenarios to inform these regulatory 
determinations. Nonetheless, though they differ slightly from the AQAT-
generated air quality estimates of the final rule control scenario 
conducted for purposes of our Step 3 analysis (as presented in section 
V.D of this document), these results using full-scale photochemical 
grid modeling complement those estimates and confirm in all cases the 
regulatory conclusions reached applying AQAT.\423\ Appendix 3A of the 
RIA presents the full results of the projected impacts of the final 
rule control scenario on ozone levels using CAMx. To briefly summarize, 
the largest reductions in ozone design values at identified receptors 
are predicted to occur in the Houston-Galveston-Brazoria, Texas area. 
In this area the reductions from the final rule case range from 0.7 to 
0.9 ppb. At most of the receptors in both the Dallas/Ft Worth and the 
New York/Coastal Connecticut areas the reductions in ozone range from 
0.4 to 0.5 ppb. At receptors in Indiana, Michigan, and Wisconsin near 
the shoreline of Lake Michigan, ozone is projected to decline by 0.3 to 
0.4 ppb, but by as much as 0.5 ppb at the receptor in Muskegon, MI. 
Reductions of 0.1 ppb are predicted in the urban and near-urban 
receptors in Chicago. In the West, ozone reductions just under 0.2 ppb 
are predicted at receptors in Denver with slightly greater reductions, 
just above 0.2 ppb, at receptors in Salt Lake City. At receptors in 
Phoenix, California, El Paso/Las Cruces, and southeast New Mexico the 
reductions in ozone are predicted to be less than 0.1 ppb.
---------------------------------------------------------------------------

    \423\ Note that the EPA's ``overcontrol'' analysis relies 
primarily on a ``Step 3'' control scenario rather than the ``full 
geography'' scenario. The CAMx modeling described here captures the 
effects of the rule as a whole and so is more akin to the ``full 
geography'' scenario, which the EPA does not believe is the 
appropriate method for conducting overcontrol analysis. Nonetheless, 
as explained in the Ozone Transport Policy Analysis Final Rule TSD, 
the results under either scenario establish no overcontrol, and the 
CAMx results presented here do not call those conclusions into 
question.
---------------------------------------------------------------------------

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

    This section describes the amendments to the regulatory text that 
implement the findings and remedy discussed elsewhere in this rule with 
respect to EGUs. The primary CFR

[[Page 36853]]

amendments are 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 
are being 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 are being amended to 
identify certain additional types of appealable decisions of the EPA 
Administrator under the amended trading program. The provisions to 
address the transition of the EGUs in certain states from the Group 2 
trading program to the Group 3 trading program are implemented in part 
through revisions to the regulations noted previously 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 
being made to the regulations for the other CSAPR trading programs in 
40 CFR part 97, subparts AAAAA through EEEEE, for conformity with the 
amended provisions of the Group 3 trading program, as discussed in 
section VI.B.13. Documents have been included in the docket for this 
rule showing all of the 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 in this rulemaking the EPA is establishing new or amended FIP 
requirements not only for the types of EGUs covered by the trading 
programs but also for certain types of industrial sources, an amendment 
to Sec.  52.38(b)(1) clarifies that the trading programs constitute the 
FIP provisions only for the sources meeting the applicability 
requirements of the trading programs. A parallel clarification is being 
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). The amendments 
to this paragraph expand the applicability of the Group 3 trading 
program to sources in the ten additional states that the EPA is adding 
to the Group 3 trading program starting with the 2023 control period 
and end the applicability of the Group 2 trading program (with the 
exception of certain provisions) for sources in seven of the ten states 
after the 2022 control period, as discussed in section VI.B.2.\424\ The 
paragraphs within Sec.  52.38(b)(2) are being 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 the EPA will no 
longer administer the state trading programs adopted under those SIP 
revisions after the 2022 control period is being added at Sec.  
52.38(b)(16)(ii)(B).
---------------------------------------------------------------------------

    \424\ Like the previous text of Sec.  52.38(b)(2), the final 
amended text expressly encompasses 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. As in effect before this rule, Sec.  52.38(b)(10), (11), 
and (12) established 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.\425\ As discussed 
in section VI.D, the EPA is retaining these SIP revision options and is 
making them available for all states covered by the Group 3 trading 
program after the geographic expansion. The option under Sec.  
52.38(b)(10) to replace allowance allocations for a single control 
period is being 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 IX.B. The 
options under Sec.  52.38(b)(11) and (12) to adopt abbreviated or full 
SIP revisions are being 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).\426\ The removal of the previous options 
for states to expand applicability of the trading programs for ozone 
season NOX emissions to certain non-EGUs and smaller EGUs, 
discussed in sections VI.D.2 and VI.D.3, is accomplished by the removal 
or revision of multiple paragraphs of Sec.  52.38(b), including most 
notably the removal of Sec.  52.38(b)(4)(i), (b)(5)(i), (b)(8)(i)-(ii), 
(b)(9)(i)-(ii), (b)(11)(i)-(iii), and (b)(12)(i)-(iii).
---------------------------------------------------------------------------

    \425\ Revisions to the deadlines for states with approved SIP 
revisions to submit their state-determined allowance allocations to 
the EPA for subsequent recordation were finalized in an earlier 
final rule in this docket. See 87 FR 52473 (August 26, 2022).
    \426\ 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 can be used 
under the amended provisions.
---------------------------------------------------------------------------

    The changes with respect to set-asides and the treatment of units 
in Indian country discussed in section VI.B.9, although implemented 
largely through amendments to the Group 3 trading program regulations, 
are also implemented in part through 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 may establish state-determined allowance allocations 
is being revised to exclude any allowances in a 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 may 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) are being revised to include the provisions of the amended 
Group 3 trading program addressing allocation and recordation of 
allowances from all types of set-asides. Finally, 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'' are being revised to 
account for the fact that at least one covered unit is already located 
in Indian country not subject to a state's CAA planning authority.
    The transitional provisions discussed in sections VI.B.12.b and 
VI.B.12.c to

[[Page 36854]]

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, will necessarily 
be implemented after the end of the 2022 control period. 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 are being added at Sec.  52.38(b)(14)(iii). Cross-
references clarifying that the EPA's allocations of the converted Group 
3 allowances are not subject to modification through SIP revisions are 
also being 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 
rule as set forth in Sec.  52.38(b)(2) are being replicated in the 
state-specific subparts of 40 CFR part 52 for each of the ten states 
that the EPA is adding to the Group 3 trading program.\427\ In each 
such state-specific CFR subpart, provisions are being 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 are also being 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.
---------------------------------------------------------------------------

    \427\ See Sec. Sec.  52.54(b) (Alabama), 52.184(a) (Arkansas), 
52.1240(d) (Minnesota), 52.1824(a) (Mississippi), 52.1326(b) 
(Missouri), 52.1492 (Nevada), 52.1930(a) (Oklahoma), 52.2283(d) 
(Texas), 52.2356 (Utah), and 52.2587(e) (Wisconsin).
---------------------------------------------------------------------------

    For each of the seven states that the EPA is removing from the 
Group 2 trading program, the provisions of the state-specific CFR 
subparts indicating that sources in the state are required to 
participate in that trading program are being revised to end that 
requirement with respect to emissions after 2022, and a further 
provision is being 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.\428\ In addition, 
for the five 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 are being removed.
---------------------------------------------------------------------------

    \428\ See Sec. Sec.  52.54(b) (Alabama), 52.184(a) (Arkansas), 
52.1824(a) (Mississippi), 52.1326(b) (Missouri), 52.1930(a) 
(Oklahoma), 52.2283(d) (Texas), and 52.2587(e) (Wisconsin).
---------------------------------------------------------------------------

    No amendments with respect to FIP requirements for EGUs are being 
made to the state-specific CFR subparts for the twelve states whose 
sources currently participate in the Group 3 trading program \429\ 
except as needed to update cross-references or to implement the changes 
related to the treatment of Indian country, as discussed in section 
IX.D.
---------------------------------------------------------------------------

    \429\ See 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 are being established 
under the new and amended FIPs in this rulemaking, several sections of 
the Group 3 trading program regulations are being 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 are being made at Sec. Sec.  97.1006(c)(3)(i), 97.1030(b)(1), 
and 97.1034(d)(2)(i), respectively. Revisions identifying the new or 
revised budgets and new unit set-asides for the control periods after 
2022 for all covered states are being made at Sec.  97.1010(a)(1) and 
(c)(2), respectively.
    Each of the enhancements to the Group 3 trading program discussed 
in section VI.B is also implemented primarily through revisions to the 
trading program regulations. The dynamic budget-setting process 
discussed in sections VI.B.1.b.i and VI.B.4 is implemented at Sec.  
97.1010(a)(2) through (4), and the associated revised process for 
determining variability limits and assurance levels discussed in 
section VI.B.5 is implemented at Sec.  97.1010(e). The Group 3 
allowance bank recalibration process discussed in sections VI.B.1.b.ii 
and VI.B.6 is implemented at Sec.  97.1026(d). The backstop daily 
NOX emissions rate component of the primary emissions 
limitation discussed in sections VI.B.1.c.i and VI.B.7 is 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. Sec.  97.1002 
and 97.1006(c)(6). The secondary emissions limitation for sources found 
responsible for exceedances of the assurance levels discussed in 
sections VI.B.1.c.ii and VI.B.8 is 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 changes relating to set-asides, the treatment of Indian 
country, and unit-level allowance allocations discussed in section 
VI.B.9 of this document are implemented through revisions to multiple 
paragraphs of Sec. Sec.  97.1010, 97.1011, and 97.1012, as well as 
limited revisions to Sec. Sec.  97.1002 (definition of ``allocate or 
allocation'') and 97.1006(b)(2). In Sec.  97.1010, paragraphs (b), (c), 
and (d) address the amounts for each control period of the Indian 
country existing unit set-asides, new unit set-asides, and Indian 
country new unit set-asides, respectively.\430\ Paragraphs (b) and (d) 
reflect the establishment of Indian country existing unit set-asides 
starting with the 2023 control period and the discontinuation of Indian 
country new unit set-asides after the 2022 control period.
---------------------------------------------------------------------------

    \430\ The former Sec.  97.1011(c), which addresses the 
relationships of set-asides and variability limits to state trading 
budgets, is being relocated to Sec.  97.1011(f).
---------------------------------------------------------------------------

    A newly added definition at Sec.  97.1002 for ``coal-derived fuel'' 
(based on the existing definition in 40 CFR 72.2) helps in 
implementation of both the backstop daily NOX emissions rate 
provisions and the unit-level allocation provisions by clarifying that 
the provisions apply without regard to how any coal combusted by a unit 
might have been processed before combustion. Another newly added 
definition at Sec.  97.1002 for ``historical control period'' helps in 
implementation of the dynamic budget-setting provisions, the secondary 
emissions limitation provisions, and the

[[Page 36855]]

unit-level allocation provisions by facilitating references to data 
reported by a unit for periods before the unit's entry into the Group 3 
trading program.
    The revisions to Sec.  97.1011 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 formerly in 
Sec.  97.1011(a)(1) requiring allocations to existing units to be made 
in the amounts provided in NODAs issued by the EPA is being 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.\431\ This split will 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 process for determining default allocations to 
existing units of allowances from state trading budgets starting with 
the 2026 control period is set forth in revised Sec.  97.1011(b), while 
the former provisions of Sec.  97.1011(b), which concern timing and 
notice procedures for allocations to new units, are being relocated to 
Sec.  97.1012. The provisions addressing incorrectly allocated 
allowances at Sec.  97.1011(c) are being streamlined by relocating the 
portions applicable to new units to Sec.  97.1012(c). In addition, as 
discussed in section VI.B.9.d, Sec.  97.1011(c)(5) is being 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 will not be reallocated to other units in the state but 
instead would be transferred to a surrender account.
---------------------------------------------------------------------------

    \431\ 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, 
is being relocated to Sec.  97.1011(a)(3). The former 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 VI.B.9, and is being removed as obsolete.
---------------------------------------------------------------------------

    The revisions to Sec.  97.1012 retain the section's current focus 
on allocations to ``new'' units, generally combining the former 
provisions at Sec.  97.1012 with the former 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) is being revised as needed 
to reflect the change in treatment of Indian country discussed in 
section VI.B.9.a, under which the new unit set-asides will 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.\432\ The timing and notice provisions 
in Sec.  97.1012(a)(13) and (b)(13) are relocated from former 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 revision addressing the disposition of 
recovered allowances, as discussed in section VI.B.9.d.
---------------------------------------------------------------------------

    \432\ Revisions are also being made to the text of Sec.  
97.1012(a) and (b) for the control periods in 2021 and 2022 
consistent with the 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 amendments to Sec.  97.1021 implement two distinct sets of 
changes discussed in sections VI.B.9 and VI.D.1. First, revisions to 
Sec.  97.1021(b) through (e) replace the previous schedule for 
recording Group 3 allowances for the 2023 and 2024 control periods 
established in the August 2022 Recordation Rule with an updated 
recordation schedule tailored to the effective date of this rule. The 
updated schedule also eliminates the unused former option for states to 
provide state-determined allowance allocations for the 2022 control 
period and establishes a substantively equivalent new option for states 
to provide state-determined allowance allocations for the 2024 control 
period. Second, revisions to Sec.  97.1021(g) through (j) begin 
recordation for Indian country existing unit set-asides starting with 
allocations for the 2023 control period, modify the text to eliminate 
references to state-determined allocations of allowances from new unit 
set-asides, and end recordation for Indian country new unit set-asides 
after allocations for the 2022 control period.
    Implementation of the revisions to the Group 3 trading program is 
also 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 VI.B.10 of this document 
are 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 the procedures for apportioning 
NOX mass emissions monitored at a common stack among the 
individual units using the common stack are being 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) is being amended to add calculation of the dynamic 
budgets to the list of administrative decisions under the trading 
program regulations that will be appealable under those procedures.

C. Transitional Provisions

    As discussed in section VI.B.12, the EPA is establishing several 
transitional provisions for sources entering the Group 3 trading 
program. The provisions discussed in section VI.B.12.a of this 
document, concerning the prorating of state emissions budgets, 
assurance levels, and unit-level allocations for the 2023 control 
period, are implemented through the Group 3 trading program 
regulations. Specifically, the state emissions budgets for the 2023 
control period will 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, will be computed under 
Sec.  97.1010(e) from the prorated state emissions budgets. Unit-level 
allocations to existing units for the 2023 control period will 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 VI.B.9.b, and will be 
announced in the notice of data availability issued under Sec.  
97.1011(a)(1) and (2) for the 2023 through 2025 control periods.
    The remaining transitional provisions are being implemented through 
the Group 2 trading program regulations.

[[Page 36856]]

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 VI.B.12.b of this document is 
implemented at Sec.  97.826(e).\433\ 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 are 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 are 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 VI.B.12.c 
of this document is implemented at Sec.  97.811(e).
---------------------------------------------------------------------------

    \433\ The provision formerly at Sec.  97.826(e)(1) is being 
relocated to Sec.  97.826(f)(1), and the provision formerly at Sec.  
97.826(e)(2) is being removed as no longer necessary.
---------------------------------------------------------------------------

    Decisions of the Administrator related to the allowance bank 
creation provisions and the allowance recall provisions are 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 VI.B.13 of this document, the EPA is 
revising 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 distinguish among units based 
on whether they are or are not covered by a state's CAA implementation 
planning authority. The revisions are 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 are 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.
    Certain other revisions to the regulatory text in the FIP and 
trading program regulations are minor simplifications and 
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 transitioning out of the 
Group 2 trading program are being modified to indicate that the amounts 
are applicable under that program only for control periods through 
2022.
    Second, as noted in sections VI.D.2 and VI.D.3, the existing 
options for states subject to the NOX SIP Call to expand 
applicability of the Group 2 trading program to include certain non-
EGUs and smaller EGUs are being eliminated. While the most directly 
affected provisions are the provisions setting forth the SIP options at 
Sec.  52.38(b)(4), (5), (8), (9), (12), and (13), as discussed in 
section IX.A of this document, the changes also render references to 
``base'' units and ``base'' sources in the regulations for the Group 2 
trading program and the Group 3 trading program obsolete. Removal of 
the references to ``base'' units and ``base'' sources affects multiple 
paragraphs of Sec. Sec.  97.802, 97.806, 97.825, 97.1002, 97.1006, and 
97.1025.
    Third, to clarify the regulatory text, the EPA is removing the 
language in the Group 3 trading program regulations that formerly 
appeared at 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) referencing supplemental amounts of allowances issued 
for the 2021 control period and associated increments to the 2021 
assurance levels (each state's assurance level increment was described 
as 21 percent of the state's supplemental amount of allowances). In 
place of the removed language, the EPA is restating the amounts of the 
2021 state emissions budgets in Sec.  97.1010(a)(1)(i) so as to include 
the supplemental amounts of allowances and is restating the amounts of 
the 2021 variability limits in Sec.  97.1010(e)(1) so as to include the 
associated assurance level increments. The revised language is 
substantively equivalent to and simpler than the previous language.
    Fourth, in 40 CFR part 75, the EPA is removing obsolete text in 
Sec.  75.73(c) and (f) to clarify the context for other text being 
added to the section, as discussed in section IX.B of this document.
    Fifth, in 40 CFR part 52, the EPA is adding Sec. Sec.  
52.38(a)(7)(iii) and 52.39(k)(3) to clarify in Sec. Sec.  52.38 and 
52.39 that the Allowance Management System housekeeping provisions 
added by the Revised CSAPR Update at Sec. Sec.  97.426(c), 97.626(c), 
and 97.726(c) in the regulations for the CSAPR NOX Annual, 
SO2 Group 1, and SO2 Group 2 trading programs, 
respectively, continue to apply after the sources in a given state have 
been removed from the programs, consistent with the text of the latter 
provisions.
    Finally, the EPA is updating cross-references throughout 40 CFR 
parts 52 and 97 for consistency with the other amendments being made in 
this rulemaking.

X. Statutory and Executive Orders Reviews

    Additional information about these statutes and Executive orders 
(``E.O.'') can be found at https://www2.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is a significant regulatory action within the scope of 
section 3(f)(1) of Executive Order 12866 that was submitted to the 
Office of Management and Budget (OMB) for review. Any changes made in 
response to Executive Order 12866 review have been documented in the 
docket. The EPA prepared an analysis of the potential costs and 
benefits associated with this action. This analysis, which is contained 
in the ``Regulatory Impact Analysis for Final Federal Good Neighbor 
Plan Addressing Regional Ozone Transport for the 2015 Ozone National 
Ambient Air Quality Standard'' [EPA-452-R-23-001], is available in the 
docket and is briefly summarized in section VIII of this document.

B. Paperwork Reduction Act (PRA)

1. Information Collection Request for Electric Generating Units
    The information collection activities in this rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the PRA. The Information Collection Request (ICR) document that 
the EPA prepared has been assigned EPA ICR number 2709.01. The EPA has 
placed a copy of the ICR in the docket for this rule, and it is briefly 
summarized here.
    The EPA is finalizing an information collection request (ICR), 
related specifically to electric generating units (EGU), for the 
Federal ``Good Neighbor Plan'' for the 2015 Ozone National Ambient Air 
Quality Standards. The 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 amendments, all EGU sources in the original twelve Group 3 states 
(Illinois, Indiana,

[[Page 36857]]

Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, 
Pennsylvania, Virginia, and West Virginia) would remain. Additionally, 
EGU sources in seven states (Alabama, Arkansas, Mississippi, Missouri, 
Oklahoma, 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 three states 
not currently covered by any CSAPR NOX ozone season trading 
program would join the revised Group 3 trading program: Minnesota, 
Nevada, and Utah. In total, EGU sources in 22 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 emissions 
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 the CSAPR NOX Ozone 
Group 2 trading programs, the reporting requirements will remain 
identical so there will be no incremental burden or cost. Certain 
sources currently reporting data will be subject to additional 
emissions reporting requirements under the rule requiring these sources 
to make a one-time monitoring plan and DAHS update. These sources 
include those with a common stack configuration and/or those that are 
large, coal-fired EGUs. Additionally, sources with a common stack 
configuration have the option to install additional monitoring 
equipment to measure emissions at each individual unit within the 
facility, and for purposes of estimating information collection costs 
and burden, the EPA assumes certain sources will utilize this option. 
Finally, the assessment of incremental cost and burden are required for 
those sources in the three 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 Nevada and Utah are already reporting data as part of the Acid Rain 
Program, thus only requiring a monitoring plan and DAHS update as well. 
There are a small number of sources in Nevada and Utah that do not 
report emissions data to the EPA under 40 CFR part 75 and will need to 
implement a Part 75 monitoring methodology which includes burdens 
related to installation, certification, and necessary updates.
    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: The EPA estimates that there would 
be 120 industry respondents.
    Frequency of response: on occasion, quarterly, and annually.
    Total estimated additional burden: 2,289 hours (per year). Burden 
is defined at 5 CFR 1320.03(b).
    Total estimated additional cost: $356,623 (per year); includes 
$182,379 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. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.
2. Information Collection Request for Non-Electric Generating Units
    The information collection activities in this final 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 2705.02. 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. 2705.02 is a new request and it addresses the burden 
associated with new regulatory requirements under the final rule. 
Owners and operators of certain non-Electric Generating Unit (non-EGU) 
industry stationary sources will potentially modify or install new 
emissions controls and associated monitoring systems to meet the 
nitrogen oxides (NOX) emissions limits of this final rule. 
The burden in this ICR reflects the new monitoring, calibrating, 
recordkeeping, reporting and testing activities required of covered 
industrial sources. This information is being collected to assure 
compliance with the final 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 the EPA, in accordance with 40 CFR chapter 
I, part 2, subpart B, shall be maintained appropriately (see 40 CFR 
part 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

[[Page 36858]]

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 boilers in Metal Ore Mining, Basic 
Chemical Manufacturing, Petroleum and Coal Products Manufacturing, and 
Pulp, Paper, and Paperboard Mills; and combustors and incinerators in 
Solid Waste Combustors and Incinerators.
    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 final rule, 
titled ``Federal ``Good Neighbor Plan'' for the 2015 Ozone National 
Ambient Air Quality Standards.''
    Estimated number of respondents: 3,328.
    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 Tables 1 through 18. 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 pipeline engine maintenance recordkeeping is conducted 
quarterly. Reporting frequency is on an annual basis.
    Total estimated burden: 11,481 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $3,823,000 (average per year); includes 
$2,400,000 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. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. The 
small entities subject to the requirements of this action are small 
businesses, which includes EGUs and non-EGUs and are described in more 
detail below. In 2026, the EPA identified a total of 29 small entities 
affected by the rule. Of these, 2 small entities may experience costs 
of greater than 1 percent of revenues. In 2026 for EGUs, the EPA 
identified 19 small entities. The EPA's decision to exclude units 
smaller than 25 MW capacity from the final rule, and exclusion of 
uncontrolled units smaller than 100 MW from backstop emissions rates 
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 ten small entities, and two small entities are 
estimated to have a cost-to-sales impact between 1.7 and 2.4 percent of 
their revenues.
    The Agency has not determined that a significant number of small 
entities potentially affected by the rule will have compliance costs 
greater than 1 percent of annual revenues during the compliance period. 
The EPA has concluded that there will be no significant economic impact 
on a substantial number of small entities (No SISNOSE) for this 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 action contains no unfunded Federal mandate for State, local, 
or Tribal governments as described in UMRA, 2 U.S.C. 1531-1538, and 
does not significantly or uniquely affect small governments. This 
action imposes no enforceable duty on any State, local, or Tribal 
government. This action contains a Federal mandate under UMRA, 2 U.S.C. 
1531-1538, that may result in expenditures of $100 million or more in 
any one year for the private sector. Accordingly, the costs and 
benefits associated with this action are discussed in section VIII of 
this preamble and in the RIA, which is in the docket for this rule. 
Additional details are presented in the RIA. This action is not subject 
to the requirements of UMRA section 203 because it contains no 
regulatory requirements that might significantly or uniquely affect 
small governments.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the National Government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

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

    This final action has tribal implications. However, it would 
neither impose substantial direct compliance costs on federally 
recognized tribal governments, nor preempt tribal law.
    The EPA is finalizing a finding that interstate transport of ozone 
precursor emissions from 23 upwind states (Alabama, Arkansas, 
California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, 
Oklahoma, Pennsylvania, Texas, Utah, Virginia, West Virginia, and 
Wisconsin) is significantly contributing to downwind nonattainment or 
interfering with maintenance of the 2015 ozone NAAQS in other states. 
The EPA is promulgating FIP requirements to eliminate interstate 
transport of ozone precursors from these 23 states. Under CAA section 
301(d)(4), the EPA is extending FIP requirements to apply in Indian 
country located within the upwind geography of the final 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. The EPA's determinations in this regard are described 
further in section III.C.2 of this document, Application of Rule in 
Indian Country and Necessary or Appropriate Finding. The EPA finds that 
all covered 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. To the EPA's knowledge, only one covered 
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. This 
final action has tribal implication because of the extension of FIP 
requirements into Indian country and because, in general, tribes have a 
vested interest in how this final rule would affect air quality.
    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 issued tribal consultation letters addressed to 574 tribes in 
February 2022 after the proposed rule was signed. The EPA received no 
further requests to facilitate

[[Page 36859]]

additional tribal consultation for the final 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 and 6 of the RIA. The EPA 
believes that the ozone-related benefits, PM2.5-related 
benefits, and CO2- related benefits from this final rule 
will further improve children's health. Additionally, the ozone and 
PM2.5 EJ exposure analyses in Chapter 7 of the RIA suggests 
that nationally, children (ages 0-17) will experience at least as great 
a reduction in ozone and PM2.5 exposures as adults (ages 18-
64) in 2023 and 2026 under all regulatory alternatives of this 
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. The EPA has prepared a Statement of 
Energy Effects for the final regulatory control alternative as follows. 
The Agency estimates a 1 percent change in retail electricity prices on 
average across the contiguous U.S. in the 2025 run year, a 4 percent 
reduction (28 GWh) in coal-fired electricity generation, a 2 percent 
increase (21 GWh) in natural gas-fired electricity generation, and a 1 
percent increase (8 GWh) in renewable electricity generation as a 
result of this final rule. The 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 rulemaking does not involve technical standards.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) directs 
Federal agencies, to the greatest extent practicable and permitted by 
law, to make environmental justice part of their mission by identifying 
and addressing, as appropriate, disproportionately high and adverse 
human health or environmental effects of their programs, policies, and 
activities on minority populations (people of color and/or indigenous 
peoples) and low-income populations.
    The EPA believes that the human health or environmental conditions 
that exist prior to this action result in or have the potential to 
result in disproportionate and adverse human health or environmental 
effects on people of color, low-income populations and/or Indigenous 
peoples. The documentation for this decision is contained in section 
VII of this document, Environmental Justice Analytical Considerations 
and Stakeholder Outreach and Engagement, and in Chapter 7, 
Environmental Justice Impacts of the RIA, which is in the public 
document. Briefly, proximity demographic analyses found larger 
percentages of Hispanics, African Americans, people below the poverty 
level, people with less educational attainment, and people 
linguistically isolated are living within 5 km and 10 km of an affected 
EGU, compared to national averages. It also finds larger percentages of 
African Americans, people below the poverty level, and with less 
educational attainment living within 5 km and 10 km of an affected non-
EGU facility. Considering the known limitations of proximity analyses, 
including the inability to assess policy-specific impacts, we also 
performed analysis of baseline EJ ozone and PM2.5 exposures. 
Baseline ozone and PM2.5 exposure analyses show that certain 
populations, such as Hispanics, Asians, those linguistically isolated, 
those less educated, and children may experience disproportionately 
higher ozone and PM2.5 exposures as compared to the national 
average. American Indians may also experience disproportionately higher 
ozone concentrations than the reference group.
    The EPA believes that this action is not likely to change existing 
disproportionate and adverse effects on people of color, low-income 
populations and/or Indigenous peoples. Specifically, we do not find 
evidence that potential EJ concerns related to ozone or 
PM2.5 exposures will be meaningfully exacerbated or 
mitigated in the regulatory alternatives under consideration as 
compared to the baseline. We infer that baseline disparities in the 
ozone and PM2.5 concentration burdens are likely to persist 
after implementation of the regulatory action or alternatives under 
consideration, due to similar modeled concentration reductions across 
population demographics. Importantly, the action described in this rule 
is expected to lower ozone and PM2.5 in many areas, 
including in ozone nonattainment areas, and thus mitigate some pre-
existing health risks across all populations evaluated.
    The EPA additionally identified and addressed environmental justice 
concerns by providing the public, including those communities 
disproportionately impacted by the burdens of pollution, opportunities 
for meaningful engagement with the EPA on this action through outreach 
activities conducted by the Agency. The information supporting this 
Executive order review is contained in section VII of this document.

K. Congressional Review Act

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. Because this action falls within the definition 
provided by 5 U.S.C. 804(2), the rule's effective date is consistent 
with 5 U.S.C. 801(a)(3).

L. 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 D.C. Circuit: (i) when the agency action 
consists of ``nationally applicable regulations promulgated, or final 
actions 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 the EPA complete discretion whether to 
invoke the exception in (ii).\434\
---------------------------------------------------------------------------

    \434\ In deciding whether to invoke the exception by making and 
publishing a finding that an action is based on a determination of 
nationwide scope or effect, the Administrator takes 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.

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

[[Page 36860]]

    This rulemaking is ``nationally applicable'' within the meaning of 
CAA section 307(b)(1). In this final action, the EPA is applying a 
uniform legal interpretation and common, nationwide analytical methods 
with respect to the requirements of CAA section 110(a)(2)(D)(i)(I) 
concerning interstate transport of pollution (i.e., ``good neighbor'' 
requirements) to promulgate FIPs that satisfy these requirements for 
the 2015 ozone NAAQS. Based on these analyses, the EPA is promulgating 
FIPs for 23 states located across a wide geographic area in eight of 
the ten EPA regions and ten Federal judicial circuits. Given that this 
action addresses implementation of the good neighbor requirements of 
CAA section 110(a)(2)(D)(i)(I) in a large number of states located 
across the country, and given the interdependent nature of interstate 
pollution transport and the common core of knowledge and analysis 
involved in promulgating these FIPs, this is a ``nationally 
applicable'' action 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 is exercising 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). In this 
final action, the EPA is interpreting and applying section 
110(a)(2)(d)(i)(I) of the CAA for the 2015 ozone NAAQS based on a 
common core of nationwide policy judgments and technical analysis 
concerning the interstate transport of pollutants throughout the 
continental U.S. In particular, the EPA is applying here the same, 
nationally consistent 4-step framework for assessing good neighbor 
obligations for the 2015 ozone NAAQS that it has applied in other 
nationally applicable rulemakings, such as CSAPR, the CSAPR Update, and 
the Revised CSAPR Update. The EPA is relying on the results from 
nationwide photochemical grid modeling using a 2016 base year and 2023 
projection year as the primary basis for its assessment of air quality 
conditions and pollution contribution levels at Step 1 and Step 2 of 
that 4-step framework and applying a nationally uniform approach to the 
identification of nonattainment and maintenance receptors across the 
entire geographic area covered by this final rule.\435\
---------------------------------------------------------------------------

    \435\ 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.
---------------------------------------------------------------------------

    The Administrator finds that this is a matter on which national 
uniformity in judicial resolution of any petitions for review is 
desirable, to take advantage of the D.C. Circuit's administrative law 
expertise, and to facilitate the orderly development of the basic law 
under the Act. The Administrator also finds that consolidated review of 
this action in the D.C. Circuit will avoid piecemeal litigation in the 
regional circuits, further judicial economy, and eliminate the risk of 
inconsistent results for different states, and that a nationally 
consistent approach to the CAA's mandate concerning interstate 
transport of ozone pollution constitutes the best use of agency 
resources. The EPA's responses to comments on the appropriate venue for 
petitions for review are contained in section 1.10 of the RTC document.
    For these reasons, this final action is nationally applicable or, 
alternatively, the Administrator is exercising the complete discretion 
afforded to him by the CAA and finds that this final action is based on 
a determination of nationwide scope or effect for purposes of CAA 
section 307(b)(1) and is publishing that finding in the Federal 
Register. Under section 307(b)(1) of the CAA, petitions for judicial 
review of this action must be filed in the United States Court of 
Appeals for the District of Columbia Circuit by August 4, 2023.
    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, promulgates new Federal 
implementation plans pursuant to the authority of section 110(c). To 
the extent any portion of this final action is not expressly identified 
under section 307(d)(1)(B), 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 emissions monitoring, Electric power 
plants, 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 S. 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 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 subpart AAAAA, except'';
0
b. In paragraph (a)(3) introductory text:
0
i. Removing ``(a)(2)(i) or (ii)'' and adding in its place ``(a)(2)''; 
and
0
ii. Removing ``the State and'' and adding in its place ``sources in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority for'';
0
c. In paragraph (a)(3)(i), removing ``State and'' and adding in its 
place

[[Page 36861]]

``State and areas of Indian country within the borders of the State 
subject to the State's SIP authority and that'';
0
d. In paragraph (a)(4) introductory text, removing ``for the State's 
sources, and'' and adding in its place ``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, and'';
0
e. Revising table 1 to paragraph (a)(4)(i)(B);
0
f. In paragraph (a)(4)(ii), removing ``deadlines for submission of 
allocations or auction results under paragraphs (a)(4)(i)(B) and (C)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (a)(4)(i)(B)'';
0
g. 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
h. Revising table 2 to paragraph (a)(5)(i)(B);
0
i. 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
j. 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
k. In paragraph (a)(5)(vi), removing ``deadlines for submission of 
allocations or auction results under paragraphs (a)(5)(i)(B) and (C)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (a)(5)(i)(B)'';
0
l. Revising paragraphs (a)(6) and (a)(7)(ii);
0
m. Adding paragraph (a)(7)(iii);
0
n. In paragraphs (a)(8)(i) and (ii), removing ``the State and'' and 
adding in its place ``sources in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
for'';
0
o. 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
p. In paragraph (b)(1), removing ``year), except'' and adding in its 
place ``year) for sources meeting the applicability criteria set forth 
in subparts BBBBB, EEEEE, and GGGGG, except'';
0
q. Redesignating paragraphs (b)(2)(i) and (ii) as paragraphs 
(b)(2)(i)(A) and (B), respectively, paragraphs (b)(2)(iii) and (iv) as 
paragraphs (b)(2)(ii)(A) and (B), respectively, and paragraph (b)(2)(v) 
as paragraph (b)(2)(iii)(A);
0
r. 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, Kansas, and 
Tennessee.'';
0
s. Adding paragraphs (b)(2)(ii)(C) and (b)(2)(iii)(B) and (C);
0
t. In paragraph (b)(3) introductory text:
0
i. Removing ``or (ii)''; and
0
ii. Removing ``the State and'' and adding in its place ``sources in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority for'';
0
u. In paragraph (b)(3)(i), removing ``State and'' and adding in its 
place ``State and areas of Indian country within the borders of the 
State subject to the State's SIP authority and that'';
0
v. Revising paragraph (b)(4) introductory text;
0
w. Removing and reserving paragraph (b)(4)(i);
0
x. Revising table 3 to paragraph (b)(4)(ii)(B) and paragraphs 
(b)(4)(iii) and (b)(5) introductory text;
0
y. Removing and reserving paragraph (b)(5)(i);
0
z. Revising table 4 to paragraph (b)(5)(ii)(B);
0
aa. 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
bb. 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
cc. Revising paragraphs (b)(5)(vii), (b)(7) introductory text, 
(b)(7)(i), and (b)(8) introductory text;
0
dd. Removing and reserving paragraphs (b)(8)(i) and (ii);
0
ee. Revising paragraph (b)(8)(iii)(A), table 5 to paragraph 
(b)(8)(iii)(B), and paragraphs (b)(8)(iv) and (b)(9) introductory text;
0
ff. Removing and reserving paragraphs (b)(9)(i) and (ii);
0
gg. Revising paragraph (b)(9)(iii)(A) and table 6 to paragraph 
(b)(9)(iii)(B);
0
hh. 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
ii. Revising paragraphs (b)(9)(vii) and (viii), (b)(10) introductory 
text, (b)(10)(i) and (ii), (b)(10)(v)(A) and (B), and (b)(11) 
introductory text;
0
jj. Removing and reserving paragraphs (b)(11)(i) and (ii);
0
kk. In paragraph (b)(11)(iii) introductory text, removing ``Sec. Sec.  
97.1011(a) and (b)(1) and 97.1012(a)'' and adding in its place ``Sec.  
97.1011(a)(1)'';
0
ll. Revising paragraph (b)(11)(iii)(A);
    mm. In paragraph (b)(11)(iii)(B):
0
i. Removing ``Sec.  97.1011(a)'' and adding in its place ``Sec.  
97.1011(a)(1)''; and
0
ii. Adding ``and'' after the semicolon;
0
nn. Removing and reserving paragraph (b)(11)(iii)(C);
0
oo. Revising paragraphs (b)(11)(iii)(D), (b)(11)(iv), and (b)(12) 
introductory text;
0
pp. Removing and reserving paragraphs (b)(12)(i) and (ii);
0
qq. In paragraph (b)(12)(iii) introductory text, removing ``Sec. Sec.  
97.1011(a) and (b)(1) and 97.1012(a)'' and adding in its place ``Sec.  
97.1011(a)(1)'';
0
rr. Revising paragraph (b)(12)(iii)(A);
0
ss. In paragraph (b)(12)(iii)(B):
0
i. Removing ``Sec.  97.1011(a)'' and adding in its place ``Sec.  
97.1011(a)(1)''; and
0
ii. Adding ``and'' after the semicolon;
0
tt. Removing and reserving paragraph (b)(12)(iii)(C);
0
uu. Revising paragraphs (b)(12)(iii)(D), (b)(12)(vi) through (viii), 
(b)(13) introductory text, and (b)(13)(i);
0
vv. In paragraph (b)(13)(ii), removing ``regulations, including any 
sources made subject to such regulations pursuant to paragraph 
(b)(9)(ii) or (b)(12)(ii) of this section, the'' and adding in its 
place ``regulations the'';
0
ww. 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
xx. In paragraph (b)(14)(i)(G), removing ``Sec.  97.826(e)'' and adding 
in its place ``Sec.  97.826(f)'';
0
yy. Revising paragraphs (b)(14)(ii) and (iii);
0
zz. In paragraph (b)(15)(i), removing ``the State and'' and adding in 
its place ``sources in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for'';
0
aaa. Revising paragraph (b)(15)(ii);
0
bbb. 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:'';

[[Page 36862]]

0
ccc. In paragraph (b)(16)(i)(A), removing ``the State and'' and adding 
in its place ``sources in the State and areas of Indian country within 
the borders of the State subject to the State's SIP authority for'';
0
ddd. Revising paragraphs (b)(16)(i)(B) and (C);
0
eee. Redesignating paragraph (b)(16)(ii) as paragraph (b)(16)(ii)(A), 
and, in newly redesignated paragraph (b)(16)(ii)(A), removing 
``(b)(2)(iv)'' and adding in its place ``(b)(2)(ii)(B)'';
0
fff. Adding paragraph (b)(16)(ii)(B); and
0
ggg. 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or 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 subject to the 
State's SIP authority, 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 
subpart AAAAA 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 pursuant to paragraph 
(a)(2)(ii) or (a)(6) of this section of the applicability of subpart 
AAAAA 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, 
the following provisions shall continue to apply with regard to all 
CSAPR NOX Annual allowances at any time allocated for any 
control period to any source or other entity in the State and areas of 
Indian country within the borders of the State subject to the State's 
SIP authority and shall apply to all entities, wherever located, that 
at any time held or hold such allowances:
    (A) The provisions of Sec.  97.426(c) of this chapter (concerning 
the transfer of CSAPR NOX Annual allowances between certain 
Allowance Management System accounts under common control).
    (B) [Reserved]
* * * * *
    (b) * * *
    (2) * * *
    (ii) * * *

[[Page 36863]]

    (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, 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, 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 emissions 
occurring on and after August 4, 2023, and in each subsequent year: 
Minnesota, Nevada, and Utah.
* * * * *
    (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 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, 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or any year thereafter............  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (iii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (b)(4)(ii) of this section by 
December 1 of the year before the year of the deadline for submission 
of allocations or auction results under paragraph (b)(4)(ii)(B) of this 
section applicable to the first control period for which the State 
wants to make allocations or hold an auction under paragraph (b)(4)(ii) 
of this section.
    (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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or any year thereafter............  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (vii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (b)(5)(ii) through (v) of this 
section by December 1 of the year before the year of the deadline for 
submission of allocations or auction results under paragraph 
(b)(5)(ii)(B) of this section applicable to the first control period 
for which the State wants to make allocations or hold an auction under 
paragraph (b)(5)(ii) of this section.
* * * * *
    (7) State-determined allocations of CSAPR NOX Ozone Season Group 2 
allowances for 2018. 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 CSAPR NOX Ozone Season Group 2 allowance 
allocation provisions replacing the provisions in Sec.  97.811(a) of 
this chapter 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 for the control period in 2018, a list of CSAPR 
NOX Ozone Season Group 2 units and the amount of CSAPR 
NOX Ozone Season Group 2 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, 2015;
* * * * *

[[Page 36864]]

    (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 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, 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
------------------------------------------------------------------------
2019 or 2020...........................  June 1, 2018.
2021 or 2022...........................  June 1, 2019.
2023 or 2024...........................  June 1, 2020.
2025 or any year thereafter............  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------

* * * * *
    (iv) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (b)(8)(iii) of this section by 
December 1 of the year before the year of the deadline for submission 
of allocations or auction results under paragraph (b)(8)(iii)(B) of 
this section applicable to the first control period for which the State 
wants to make allocations or hold an auction under paragraph 
(b)(8)(iii) of this section.
    (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 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
------------------------------------------------------------------------
2019 or 2020...........................  June 1, 2018.
2021 or 2022...........................  June 1, 2019.
2023 or 2024...........................  June 1, 2020.
2025 or 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 Sec. Sec.  97.802, 97.806(c)(2), and 97.825 and may 
modify any portion of the CSAPR Federal Implementation Plan that is not 
replaced by the SIP revision to include these provisions; and
    (viii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (b)(9)(iii) through (vi) of this 
section by December 1 of the year before the year of the deadline for 
submission of allocations or auction results under paragraph 
(b)(9)(iii)(B) of this section applicable to the first control period 
for which the State wants to make allocations or hold an auction under 
paragraph (b)(9)(iii) of this section.
    (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 sources in the State and areas of Indian 
country within the borders of the State subject to the State's SIP 
authority for 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

[[Page 36865]]

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 Indian country existing unit set-aside and the new 
unit set-aside;
* * * * *
    (v) * * *
    (A) By August 4, 2023, 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 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, 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 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 Indian country existing 
unit set-aside, the new unit set-aside, and the amount of any CSAPR 
NOX Ozone Season Group 3 allowances already allocated and 
recorded by the Administrator;
* * * * *
    (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; and
    (iv) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (b)(11)(iii) of this section by 
December 1 of the year before the year of the deadline for submission 
of allocations or auction results under paragraph (b)(11)(iii)(B) of 
this section applicable to the first control period for which the State 
wants to make allocations or hold an auction under paragraph 
(b)(11)(iii) of this section.
    (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 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) * * *
    (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 Indian country existing 
unit set-aside, the new unit set-aside, and the amount of any CSAPR 
NOX Ozone Season Group 3 allowances already allocated and 
recorded by the Administrator;
* * * * *
    (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 any 
portion of the CSAPR Federal Implementation Plan that is not replaced 
by the SIP revision;
    (vii) Provided that, if before the Administrator's approval of the 
SIP revision 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 ``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 Sec. Sec.  97.1002, 97.1006(c)(2), and 
97.1025, and further provided that, if and when after the 
Administrator's approval of the SIP revision 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 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
    (viii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (b)(12)(iii) through (vi) of 
this section by December 1 of the year before the year of the deadline 
for submission of allocations or auction results under paragraph 
(b)(12)(iii)(B) of this section applicable to the first control period 
for which the State wants to make allocations or hold an auction under 
paragraph (b)(12)(iii) of this section.
    (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

[[Page 36866]]

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 pursuant to paragraph 
(b)(2)(i)(B), (b)(2)(ii)(B) or (C), or (b)(13)(i) of this section 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, 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 allocated for any control period to any source 
or other entity in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority and shall 
apply to all entities, wherever located, that at any time held or hold 
such allowances:
    (A) The provisions of Sec. Sec.  97.526(c) and 97.826(c) of this 
chapter (concerning the transfer of CSAPR NOX Ozone Season 
Group 1 allowances and CSAPR NOX Ozone Season Group 2 
allowances between certain Allowance Management System accounts under 
common control);
    (B) The provisions of Sec. Sec.  97.526(d) and 97.826(d) and (e) of 
this chapter (concerning the conversion of unused CSAPR NOX 
Ozone Season Group 1 allowances allocated for specified control periods 
to different amounts of CSAPR NOX Ozone Season Group 2 
allowances or CSAPR NOX Ozone Season Group 3 allowances and 
the conversion of unused CSAPR NOX Ozone Season Group 2 
allowances allocated for specified control periods to different amounts 
of CSAPR NOX Ozone Season Group 3 allowances); and
    (C) The provisions of Sec.  97.811(d) and (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 specified 
control periods and recorded in specified Allowance Management System 
accounts).
    (15) * * *
    (ii) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(4) of this section as 
replacing the CSAPR NOX Ozone Season Group 1 allowance 
allocation provisions in Sec. Sec.  97.511(a) and (b)(1) and 97.512(a) 
of this chapter 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 for the control period in 2017 or any subsequent year: 
[none].
* * * * *
    (16) * * *
    (i) * * *
    (B) For each of the following States, the Administrator has 
approved a SIP revision under paragraph (b)(8) of this section as 
replacing the CSAPR NOX Ozone Season Group 2 allowance 
allocation provisions in Sec. Sec.  97.811(a) and (b)(1) and 97.812(a) 
of this chapter 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 for the control period in 2019 or any subsequent year: New 
York.
    (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 sources in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority for 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 allowance 
allocation provisions in Sec.  97.1011(a)(1) of this chapter 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 for 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].

[[Page 36867]]


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 subparts CCCCC and DDDDD, except'';
0
b. In paragraph (d) introductory text, removing ``the State and'' and 
adding in its place ``sources in the State and areas of Indian country 
within the borders of the State subject to the State's SIP authority 
for'';
0
c. In paragraph (d)(1), removing ``State and'' and adding in its place 
``State and areas of Indian country within the borders of the State 
subject to the State's SIP authority and that'';
0
d. In paragraph (e) introductory text, removing ``for the State's 
sources, and'' and adding in its place ``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, and'';
0
e. Revising table 1 to paragraph (e)(1)(ii);
0
f. In paragraph (e)(2), removing ``deadlines for submission of 
allocations or auction results under paragraphs (e)(1)(ii) and (iii)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (e)(1)(ii)'';
0
g. 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
h. Revising table 2 to paragraph (f)(1)(ii);
0
i. 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
j. 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
k. In paragraph (f)(6), removing ``deadlines for submission of 
allocations or auction results under paragraphs (f)(1)(ii) and (iii)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (f)(1)(ii)'';
0
l. In paragraph (g) introductory text:
0
i. Removing ``(c)(1) or (2)'' and adding in its place ``(c)''; and
0
ii. Removing ``the State and'' and adding in its place ``sources in the 
State and areas of Indian country within the borders of the State 
subject to the State's SIP authority for'';
0
m. In paragraph (g)(1), removing ``State and'' and adding in its place 
``State and areas of Indian country within the borders of the State 
subject to the State's SIP authority and that'';
0
n. In paragraph (h) introductory text, removing ``for the State's 
sources, and'' and adding in its place ``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, and'';
0
o. Revising table 3 to paragraph (h)(1)(ii);
0
p. In paragraph (h)(2), removing ``deadlines for submission of 
allocations or auction results under paragraphs (h)(1)(ii) and (iii)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (h)(1)(ii)'';
0
q. 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
r. Revising table 4 to paragraph (i)(1)(ii);
0
s. 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
t. 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
u. In paragraph (i)(6), removing ``deadlines for submission of 
allocations or auction results under paragraphs (i)(1)(ii) and (iii)'' 
and adding in its place ``deadline for submission of allocations or 
auction results under paragraph (i)(1)(ii)'';
0
v. Revising paragraphs (j) and (k)(2);
0
w. Adding paragraph (k)(3);
0
x. In paragraphs (l)(1) and (2), removing ``the State and'' and adding 
in its place ``sources in the State and areas of Indian country within 
the borders of the State subject to the State's SIP authority for'';
0
y. In paragraph (l)(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:''.
0
z. In paragraphs (m)(1) and (2), removing ``the State and'' and adding 
in its place ``sources in the State and areas of Indian country within 
the borders of the State subject to the State's SIP authority for''; 
and
0
aa. In paragraph (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 and addition 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or any year thereafter............  June 1 of the year before the
                                          year of the control period.
------------------------------------------------------------------------


[[Page 36868]]

* * * * *
    (f) * * *
    (1) * * *
    (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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or 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
------------------------------------------------------------------------
2017 or 2018...........................  June 1, 2016.
2019 or 2020...........................  June 1, 2017.
2021 or 2022...........................  June 1, 2018.
2023...................................  June 1, 2019.
2024...................................  June 1, 2020.
2025 or 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 subject to the State's SIP authority, 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.
    (3) Notwithstanding any discontinuation pursuant to paragraph

[[Page 36869]]

(c)(2) or (j) of this section of the applicability of subpart CCCCC or 
DDDDD 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, 
the following provisions shall continue to apply with regard to all 
CSAPR SO2 Group 1 allowances and CSAPR SO2 Group 
2 allowances at any time allocated for any control period to any source 
or other entity in the State and areas of Indian country within the 
borders of the State subject to the State's SIP authority and shall 
apply to all entities, wherever located, that at any time held or hold 
such allowances:
    (i) The provisions of Sec. Sec.  97.626(c) and 97.726(c) of this 
chapter (concerning the transfer of CSAPR SO2 Group 1 
allowances and CSAPR SO2 Group 2 allowances between certain 
Allowance Management System accounts under common control).
    (ii) [Reserved]
* * * * *

0
4. Add Sec. Sec.  52.40 through 52.46 to subpart A 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?
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, the Pulp, Paper, and Paperboard Mills Industries, 
Metal Ore Mining, and the Iron and Steel and Ferroalloy 
Manufacturing Industries?
52.46 What are the requirements of the Federal Implementation Plans 
(FIPs) relating to ozone season emissions of nitrogen oxides from 
Municipal Waste Combustors?
* * * * *


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) Purpose. 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) Definitions. The terms used in this section and Sec. Sec.  
52.41 through Sec.  52.46 are defined as follows:
    Calendar year means the period between January 1 and December 31, 
inclusive, for a given year.
    Existing affected unit means any affected unit for which 
construction commenced before August 4, 2023.
    New affected unit means any affected unit for which construction 
commenced on or after August 4, 2023.
    Operator means any person who operates, controls, or supervises an 
affected unit and shall include, but not be limited to, any holding 
company, utility system, or plant manager of such affected unit.
    Owner means any holder of any portion of the legal or equitable 
title in an affected unit.
    Potential to emit means the maximum capacity of a unit to emit a 
pollutant under its physical and operational design. Any physical or 
operational limitation on the capacity of the unit to emit a pollutant, 
including air pollution control equipment and restrictions on hours of 
operation or on the type or amount of material combusted, stored, or 
processed, shall be treated as part of its design only if the 
limitation or the effect it would have on emissions is federally 
enforceable. Secondary emissions do not count in determining the 
potential to emit of a unit.
    Rolling average means the weighted average of all data, meeting 
quality assurance and quality control (QA/QC) requirements in this part 
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.
    (c) General requirements. (1) The NOX emissions 
limitations or emissions control requirements 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. Sec.  52.41 for engines in the 
Pipeline Transportation of Natural Gas Industry, 52.42 for kilns in the 
Cement and Concrete Product Manufacturing Industry, 52.43 for reheat 
furnaces in the Iron and Steel Mills and Ferroalloy Manufacturing 
Industry, 52.44 for furnaces in the Glass and Glass Product 
Manufacturing Industry, 52.45 for boilers in the Iron and Steel Mills 
and Ferroalloy Manufacturing, Metal Ore Mining, Basic Chemical 
Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp, 
Paper, and Paperboard Mills industries, and 52.46 for Municipal Waste 
Combustors.
    (2) The provisions of this section or Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46 apply to affected 
units 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, 
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, 
Pennsylvania, Texas, Utah, Virginia, and West Virginia.
    (3) The testing, monitoring, recordkeeping, and reporting 
requirements of this section or Sec.  52.41, Sec.  52.42, Sec.  52.43, 
Sec.  52.44, Sec.  52.45, or Sec.  52.46 only apply during the ozone 
season, except as otherwise specified in these sections. Additionally, 
if an owner or operator of an affected unit chooses to conduct a 
performance or compliance test outside of the ozone season, all 
recordkeeping, reporting, and notification requirements associated

[[Page 36870]]

with that test shall apply, without regard to whether they occur during 
the ozone season.
    (d) Requests for extension of compliance. (1) The owner or operator 
of an existing affected unit under Sec.  52.41, Sec.  52.42, Sec.  
52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46 that cannot comply with 
the applicable requirements in those sections by May 1, 2026, due to 
circumstances entirely beyond the owner or operator's control, may 
request an initial compliance extension to a date certain no later than 
May 1, 2027. The extension request must contain a demonstration of 
necessity consistent with the requirements of paragraph (d)(3) of this 
section.
    (2) If, after the EPA has granted a request for an initial 
compliance extension, the source remains unable to comply with the 
applicable requirements in Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  
52.44, Sec.  52.45, or Sec.  52.46 by the extended compliance date due 
to circumstances entirely beyond the owner or operator's control, the 
owner or operator may apply for a second compliance extension to a date 
certain no later than May 1, 2029. The extension request must contain 
an updated demonstration of necessity consistent with the requirements 
of paragraph (d)(3) of this section.
    (3) Each request for a compliance extension shall demonstrate that 
the owner or operator has taken all steps possible to install the 
controls necessary for compliance with the applicable requirements in 
Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or 
Sec.  52.46 by the applicable compliance date and shall:
    (i) Identify each affected unit for which the owner or operator is 
seeking the compliance extension;
    (ii) Identify and describe the controls to be installed at each 
affected unit to comply with the applicable requirements in Sec.  
52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  
52.46;
    (iii) Identify the circumstances entirely beyond the owner or 
operator's control that necessitate additional time to install the 
identified controls;
    (iv) Identify the date(s) by which on-site construction, 
installation of control equipment, and/or process changes will be 
initiated;
    (v) Identify the owner or operator's proposed compliance date. A 
request for an initial compliance extension under paragraph (d)(1) of 
this section must specify a proposed compliance date no later than May 
1, 2027, and state whether the owner or operator anticipates a need to 
request a second compliance extension. A request for a second 
compliance extension under paragraph (d)(2) of this section must 
specify a proposed compliance date no later than May 1, 2029, and 
identify additional actions taken by the owner or operator to ensure 
that the affected unit(s) will be in compliance with the applicable 
requirements in this section by that proposed compliance date;
    (vi) Include all information obtained from control technology 
vendors demonstrating that the identified controls cannot be installed 
by the applicable compliance date;
    (vii) Include any and all contract(s) entered into for the 
installation of the identified controls or an explanation as to why no 
contract is necessary or obtainable; and
    (viii) Include any permit(s) obtained for the installation of the 
identified controls or, where a required permit has not yet been 
issued, a copy of the permit application submitted to the permitting 
authority and a statement from the permitting authority identifying its 
anticipated timeframe for issuance of such permit(s).
    (4) Each request for a compliance extension shall be submitted via 
the Compliance and Emissions Data Reporting Interface (CEDRI) or 
analogous electronic submission system provided by the EPA no later 
than 180 days prior to the applicable compliance date. Until an 
extension has been granted by the Administrator under this section, the 
owner or operator of an affected unit shall comply with all applicable 
requirements of this section and shall remain subject to the May 1, 
2026 compliance date or the initial extended compliance date, as 
applicable. A denial will be effective as of the date of denial.
    (5) The owner or operator of an affected unit who has requested a 
compliance extension under this paragraph (d)(5) and is required to 
have a title V permit shall apply to have the relevant title V permit 
revised to incorporate the conditions of the extension of compliance. 
The conditions of a compliance extension granted under this paragraph 
(d)(5) will be incorporated into the affected unit's title V permit 
according to the provisions of an EPA-approved state operating permit 
program or the Federal title V regulations in 40 CFR part 71, whichever 
apply.
    (6) Based on the information provided in any request made under 
paragraph (d) of this section or other information, the Administrator 
may grant an extension of time to comply with applicable requirements 
in Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or 
Sec.  52.46 consistent with the provisions of paragraph (d)(1) or (2) 
of this section. The decision to grant an extension will be provided by 
notification via the CEDRI or analogous electronic submission system 
provided by the EPA and publicly available, and will identify each 
affected unit covered by the extension; specify the termination date of 
the extension; and specify any additional conditions that the 
Administrator deems necessary to ensure timely installation of the 
necessary controls (e.g., the date(s) by which on-site construction, 
installation of control equipment, and/or process changes will be 
initiated).
    (7) The Administrator will provide notification via the CEDRI or 
analogous electronic submission system provided by the EPA to the owner 
or operator of an affected unit who has requested a compliance 
extension under this paragraph (d)(7) whether the submitted request is 
complete, that is, whether the request contains sufficient information 
to make a determination, within 60 calendar days after receipt of the 
original request and within 60 calendar days after receipt of any 
supplementary information.
    (8) The Administrator will provide notification via the CEDRI or 
analogous electronic submission system provided by the EPA, which shall 
be publicly available, to the owner or operator of a decision to grant 
or intention to deny a request for a compliance extension within 60 
calendar days after providing written notification pursuant to 
paragraph (d)(7) of this section that the submitted request is 
complete.
    (9) Before denying any request for an extension of compliance, the 
Administrator will provide notification via the CEDRI or analogous 
electronic submission system provided by the EPA to the owner or 
operator in writing of the Administrator's intention to issue the 
denial, together with:
    (i) Notice of the information and findings on which the intended 
denial is based; and
    (ii) Notice of opportunity for the owner or operator to present via 
the CEDRI or analogous electronic submission system provided by the 
EPA, within 15 calendar days after he/she is notified of the intended 
denial, additional information or arguments to the Administrator before 
further action on the request.
    (10) The Administrator's final decision to deny any request for an 
extension will be provided via the CEDRI or analogous electronic 
submission system provided by the EPA and publicly available, and will 
set forth the specific grounds on which the denial is based. The final 
decision will be made within 60 calendar days after presentation of 
additional information

[[Page 36871]]

or argument (if the request is complete), or within 60 calendar days 
after the deadline for the submission of additional information or 
argument under paragraph (d)(9)(ii) of this section, if no such 
submission is made.
    (11) The granting of an extension under this section shall not 
abrogate the Administrator's authority under section 114 of the Clean 
Air Act (CAA or the Act).
    (e) Requests for case-by-case emissions limits. (1) The owner or 
operator of an existing affected unit under Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46 that cannot 
comply with the applicable requirements in those sections due to 
technical impossibility or extreme economic hardship may submit to the 
Administrator, by August 5, 2024, a request for approval of a case-by-
case emissions limit. The request shall contain information sufficient 
for the Administrator to confirm that the affected unit is unable to 
comply with the applicable emissions limit, due to technical 
impossibility or extreme economic hardship, and to establish an 
appropriate alternative case-by-case emissions limit for the affected 
unit. Until a case-by-case emissions limit has been approved by the 
Administrator under this section, the owner or operator shall remain 
subject to all applicable requirements in Sec.  52.41, Sec.  52.42, 
Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46. A denial will be 
effective as of the date of denial.
    (2) Each request for a case-by-case emissions limit shall include, 
but not be limited to, the following:
    (i) A demonstration that the affected unit cannot achieve the 
applicable emissions limit with available control technology due to 
technical impossibility or extreme economic hardship.
    (A) A demonstration of technical impossibility shall include:
    (1) Uncontrolled NOX emissions for the affected unit 
established with a CEMS, or stack tests obtained during steady state 
operation in accordance with the applicable reference test methods of 
40 CFR part 60, appendix A-4, any alternative test method approved by 
the EPA as of June 5, 2023, under 40 CFR 59.104(f), 60.8(b)(3), 
61.13(h)(1)(ii), 63.7(e)(2)(ii)(2), or 65.158(a)(2) and available at 
the EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods and procedures approved by 
the EPA through notice-and-comment rulemaking; and
    (2) A demonstration that the affected unit cannot meet the 
applicable emissions limit even with available control technology, 
including:
    (i) Stack test data or other emissions data for the affected unit; 
or
    (ii) A third-party engineering assessment demonstrating that the 
affected unit cannot meet the applicable emissions limit with available 
control technology.
    (B) A demonstration of extreme economic hardship shall include at 
least three vendor estimates of the costs of installing control 
technology necessary to meet the applicable emissions limit and other 
information that demonstrates, to the satisfaction of the 
Administrator, that the cost of complying with the applicable emissions 
limit would present an extreme economic hardship relative to the costs 
borne by other comparable sources in the industry.
    (ii) An analysis of available control technology options and a 
proposed case-by-case emissions limit that represents the lowest 
emissions limitation technically achievable by the affected unit 
without causing extreme economic hardship relative to the costs borne 
by other comparable sources in the industry. The owner or operator may 
propose additional measures to reduce NOX emissions, such as 
operational standards or work practice standards.
    (iii) Calculations of the NOX emissions reduction to be 
achieved through implementation of the proposed case-by-case emissions 
limit and any additional proposed measures, the difference between this 
NOX emissions reduction level and the NOX 
emissions reductions that would have occurred if the affected unit 
complied with the applicable emissions limitations in Sec.  52.41, 
Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46, and 
a description of the methodology used for these calculations.
    (3) The owner or operator of an affected unit who has requested a 
case-by-case emissions limit under this paragraph (e)(3) and is 
required to have a title V permit shall apply to have the relevant 
title V permit revised to incorporate the case-by-case emissions limit. 
Any case-by-case emissions limit approved under this paragraph (e)(3) 
will be incorporated into the affected unit's title V permit according 
to the provisions of an EPA-approved state operating permit program or 
the Federal title V regulations in 40 CFR part 71, whichever apply.
    (4) Based on the information provided in any request made under 
this paragraph (e)(4) or other information, the Administrator may 
approve a case-by-case emissions limit that will apply to an affected 
unit in lieu of the applicable emissions limit in Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46. The 
decision to approve a case-by-case emissions limit will be provided via 
the CEDRI or analogous electronic submission system provided by the EPA 
in paragraph (d) of this section and publicly available, and will 
identify each affected unit covered by the case-by-case emissions 
limit.
    (5) The Administrator will provide notification via the CEDRI or 
analogous electronic submission system provided by the EPA in paragraph 
(d) of this section to the owner or operator of an affected unit who 
has requested a case-by-case emissions limit under this paragraph 
(e)(5) whether the submitted request is complete, that is, whether the 
request contains sufficient information to make a determination, within 
60 calendar days after receipt of the original request and within 60 
calendar days after receipt of any supplementary information.
    (6) The Administrator will provide notification via the CEDRI or 
analogous electronic submission system described by the EPA in 
paragraph (d) of this section, which shall be publicly available, to 
the owner or operator of a decision to approve or intention to deny the 
request within 60 calendar days after providing notification pursuant 
to paragraph (e)(5) of this section that the submitted request is 
complete.
    (7) Before denying any request for a case-by-case emissions limit, 
the Administrator will provide notification via the CEDRI or analogous 
electronic submission system provided by the EPA to the owner or 
operator in writing of the Administrator's intention to issue the 
denial, together with:
    (i) Notice of the information and findings on which the intended 
denial is based; and
    (ii) Notice of opportunity for the owner or operator to present via 
the CEDRI or analogous electronic submission system provided by the 
EPA, within 15 calendar days after he/she is notified of the intended 
denial, additional information or arguments to the Administrator before 
further action on the request.
    (8) The Administrator's final decision to deny any request for a 
case-by-case emissions limit will be provided by notification via the 
CEDRI or analogous electronic submission system provided by the EPAand 
publicly available, and will set forth the specific grounds on which 
the denial is based. The final decision will be made within 60 calendar 
days after presentation of additional information or argument (if the 
request is complete), or within 60 calendar days after the deadline for 
the

[[Page 36872]]

submission of additional information or argument under paragraph 
(e)(7)(ii) of this section, if no such submission is made.
    (9) The approval of a case-by-case emissions limit under this 
section shall not abrogate the Administrator's authority under section 
114 of the Act.
    (f) Recordkeeping requirements. (1) The owner or operator of an 
affected unit subject to the provisions of this section or Sec.  52.41, 
Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46 
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 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.
    (2) Any records required to be maintained by Sec.  52.41, Sec.  
52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  52.46 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.
    (g) CEDRI reporting requirements. (1) You shall submit the results 
of the performance test following the procedures specified in 
paragraphs (g)(1)(i) through (iii) of this section:
    (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 Sec.  
52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  
52.46, 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)(A) The EPA will make all the information submitted through 
CEDRI available to the public without further notice to you. Do not use 
CEDRI to submit information you claim as confidential business 
information (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) or (2) of this section, you should 
submit a complete file, including information claimed to be CBI, to the 
EPA.
    (B) 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.
    (C) Clearly mark the part or all of the information that you claim 
to be CBI. Information not marked as CBI may be authorized for public 
release without prior notice. Information marked as CBI will not be 
disclosed except in accordance with procedures set forth in 40 CFR part 
2.
    (D) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the Office of Air Quality Planning and 
Standards (OAQPS) CBI Office at the email address [email protected], and 
as described in this paragraph (g), should include clear CBI markings 
and be flagged to the attention of Lead of 2015 Ozone Transport FIP. 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.
    (E) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711, 
Attention Lead of 2015 Ozone Transport FIP. The mailed CBI material 
should be double wrapped and clearly marked. Any CBI markings should 
not show through the outer envelope.
    (F) All CBI claims must be asserted at the time of submission. 
Anything submitted using CEDRI cannot later be claimed CBI. 
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.
    (G) You must submit the same file submitted to the CBI office with 
the CBI omitted to the EPA via the EPA's CDX as described in paragraphs 
(g)(1) and (2) of this section.
    (2) Annual reports must be submitted via CEDRI or analogous 
electronic reporting approach provided by the EPA to report data 
required by Sec.  52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  
52.45, or Sec.  52.46.
    (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 (g)(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.

[[Page 36873]]

    (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 (g)(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 unit, its 
contractors, or any entity controlled by the affected unit 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 unit (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.  52.41  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 in this paragraph (a) shall 
have the meaning given to them in the Act and in subpart A of 40 CFR 
part 60.
    Affected unit means an engine meeting the applicability criteria of 
this section.
    Cap means the total amount of NOX emissions, in tons per 
day on a 30-day rolling average basis, that is collectively allowed 
from all of the affected units covered by a Facility-Wide Averaging 
Plan and is calculated as the sum each affected unit's NOX 
emissions at the emissions limit applicable to such unit under 
paragraph (c) of this section, converted to tons per day in accordance 
with paragraph (d)(3) of this section.
    Emergency engine means any stationary reciprocating internal 
combustion engine (RICE) that meets all of the criteria in paragraphs 
(i) and (ii) of this definition. All emergency stationary RICE must 
comply with the requirements specified in paragraph (b)(1) of this 
section in order to be considered emergency engines. If the engine does 
not comply with the requirements specified in paragraph (b)(1), it is 
not considered an emergency engine under this section.
    (i) The stationary engine is operated to provide electrical power 
or mechanical work during an emergency situation. Examples include 
stationary RICE used to produce power for critical networks or 
equipment (including power supplied to portions of a facility) when 
electric power from the local utility (or the normal power source, if 
the facility runs on its own power production) is interrupted, or 
stationary RICE used to pump water in the case of fire or flood, etc.
    (ii) The stationary RICE is operated under limited circumstances 
for purposes other than those identified in paragraph (i) of this 
definition, as specified in paragraph (b)(1) of this section.
    Facility means all of the pollutant-emitting activities which 
belong to the same industrial grouping, are located on one or more 
contiguous or adjacent properties, and are under the control of the 
same person (or persons under common control). Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same ``Major Group'' (i.e., which have the same 
first two digit code as described in the Standard Industrial 
Classification Manual, 1987). For purposes of this section, a facility 
may not extend beyond the 20 states identified in Sec.  52.40(b)(2).
    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.
    Local Distribution Companies (LDCs) are companies that own or 
operate distribution pipelines, but not interstate pipelines or 
intrastate pipelines, that physically deliver natural gas to end users 
and that are within a single state that are regulated as separate 
operating companies by State public utility commissions or that operate 
as independent municipally-owned distribution systems. LDCs do not 
include pipelines (both interstate and intrastate) delivering natural 
gas directly to major industrial users and farm taps upstream of the 
local distribution company inlet.
    Local Distribution Company (LDC) custody transfer station means a 
metering station where the LDC receives a natural gas supply from an 
upstream supplier, which may be an interstate transmission pipeline or 
a local natural gas producer, for delivery to customers through the 
LDC's intrastate transmission or distribution lines.
    Nameplate rating means the manufacturer's maximum design 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

[[Page 36874]]

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.
    Natural gas processing plant means any processing site engaged in 
the extraction of natural gas liquids from field gas, fractionation of 
mixed natural gas liquids to natural gas products, or both. A Joule-
Thompson valve, a dew point depression valve, or an isolated or 
standalone Joule-Thompson skid is not a natural gas processing plant.
    Natural gas production facility means all equipment at a single 
stationary source directly associated with one or more natural gas 
wells upstream of the natural gas processing plant. This equipment 
includes, but is not limited to, equipment used for storage, 
separation, treating, dehydration, artificial lift, combustion, 
compression, pumping, metering, monitoring, and flowline.
    Operating day means a 24-hour period beginning at 12:00 midnight 
during which any fuel is combusted at any time in the engine.
    Pipeline transportation of natural gas means the movement of 
natural gas through an interconnected network of compressors and 
pipeline components, including the compressor and pipeline network used 
to transport the natural gas from processing plants over a distance 
(intrastate or interstate) to and from storage facilities, to large 
natural gas end[hyphen]users, and prior to delivery to a ``local 
distribution company custody transfer station'' (as defined in this 
section) of an LDC that provides the natural gas to end-users. Pipeline 
transportation of natural gas does not include natural gas production 
facilities, natural gas processing plants, or the portion of a 
compressor and pipeline network that is upstream of a natural gas 
processing plant.
    Reciprocating internal combustion engine (RICE) 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[hyphen]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 emissions control technology for nitrogen oxides 
(NOX) (such as pre[hyphen]combustion chambers) will be 
considered lean burn engines. Existing affected unit where there are no 
manufacturer's recommendations regarding air/fuel ratio will be 
considered rich burn engines if the excess oxygen content of 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[hyphen]to[hyphen]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[hyphen]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, other than an emergency 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(c)(2), including Indian country located within the borders of any 
such State(s).
    (1) For purposes of this section, the owner or operator of an 
emergency stationary RICE must operate the RICE according to the 
requirements in paragraphs (b)(1)(i) through (iii) of this section to 
be treated as an emergency stationary RICE. In order for stationary 
RICE to be treated as an emergency RICE under this subpart, any 
operation other than emergency operation, maintenance and testing, and 
operation in non-emergency situations for up to 50 hours per year, as 
described in paragraphs (b)(1)(i) through (iii), is prohibited. If you 
do not operate the RICE according to the requirements in paragraphs 
(b)(1)(i) through (iii), the RICE will not be considered an emergency 
engine under this section and must meet all requirements for affected 
units in this section.
    (i) There is no time limit on the use of emergency stationary RICE 
in emergency situations.
    (ii) The owner or operator may operate your emergency stationary 
RICE for maintenance checks and readiness testing for a maximum of 100 
hours per calendar year, provided that the tests are recommended by a 
Federal, state, or local government agency, the manufacturer, the 
vendor, or the insurance company associated with the engine. Any 
operation for non-emergency situations as allowed by paragraph 
(b)(1)(iii) of this section counts as part of the 100 hours per 
calendar year allowed by paragraph (b)(1)(ii) of this section. The 
owner or operator may petition the Administrator for approval of 
additional hours to be used for maintenance checks and readiness 
testing, but a petition is not required if the owner or operator 
maintains records confirming that Federal, state, or local standards 
require maintenance and testing of emergency RICE beyond 100 hours per 
calendar year. Any approval of a petition for additional hours granted 
by the Administrator under 40 CFR part 63, subpart ZZZZ, shall 
constitute approval by the Administrator of the same petition under 
this paragraph (b)(1)(ii).
    (iii) Emergency stationary RICE may be operated for up to 50 hours 
per calendar year in non-emergency situations. The 50 hours of 
operation in non-emergency situations are counted as part of the 100 
hours per calendar year for maintenance and testing provided in 
paragraph (b)(1)(ii) of this section.
    (2) If you own or operate a natural gas-fired two stroke lean burn 
spark ignition engine manufactured after July 1, 2007 that is meeting 
the applicable emissions limits in 40 CFR part 60, subpart JJJJ, table 
1, the engine is not an affected unit under this section and you do not 
have to comply with the requirements of this section.
    (3) If you own or operate a natural gas-fired four stroke lean or 
rich burn spark ignition engine manufactured after July 1, 2010, that 
is meeting the applicable emissions limits in 40 CFR part 60, subpart 
JJJJ, table 1, the engine is not an affected unit under this section 
and you do not have to comply with the requirements of this section.
    (c) Emissions limitations. If you are the owner or operator of an 
affected unit, you must meet the following emissions limitations on a 
30-day rolling average basis during the 2026 ozone season and in each 
ozone season thereafter:
    (1) Natural gas-fired four stroke rich burn spark ignition engine: 
1.0 grams per hp-hour (g/hp-hr);
    (2) Natural gas-fired four stroke lean burn spark ignition engine: 
1.5 g/hp-hr; and

[[Page 36875]]

    (3) Natural gas-fired two stroke lean burn spark ignition engine: 
3.0 g/hp-hr.
    (d) Facility-Wide Averaging Plan. If you are the owner or operator 
of a facility containing more than one affected unit, you may submit a 
request via the CEDRI or analogous electronic submission system 
provided by the EPA to the Administrator for approval of a proposed 
Facility-Wide Averaging Plan as an alternative means of compliance with 
the applicable emissions limits in paragraph (c) of this section. Any 
such request shall be submitted to the Administrator on or before 
October 1st of the year prior to each emissions averaging year. The 
Administrator will approve a proposed Facility-Wide Averaging Plan 
submitted under this paragraph (d) if the Administrator determines that 
the proposed Facility-Wide Averaging Plan meets the requirements of 
this paragraph (d), will provide total emissions reductions equivalent 
to or greater than those achieved by the applicable emissions limits in 
paragraph (c), and identifies satisfactory means for determining 
initial and continuous compliance, including appropriate testing, 
monitoring, recordkeeping, and reporting requirements. You may only 
include affected units (i.e., engines meeting the applicability 
criteria in paragraph (b) of this section) in a Facility-Wide Averaging 
Plan. Upon EPA approval of a proposed Facility-Wide Averaging Plan, you 
cannot withdraw any affected unit listed in such plan, and the terms of 
the plan may not be changed unless approved in writing by the 
Administrator.
    (1) Each request for approval of a proposed Facility-Wide Averaging 
Plan shall include, but not be limited to:
    (i) The address of the facility;
    (ii) A list of all affected units at the facility that will be 
covered by the plan, identified by unit identification number, the 
engine manufacturer's name, and model;
    (iii) For each affected unit, a description of any existing 
NOX emissions control technology and the date of 
installation, and a description of any NOX emissions control 
technology to be installed and the projected date of installation;
    (iv) Identification of the emissions cap, calculated in accordance 
with paragraph (d)(3) of this section, that all affected units covered 
by the proposed Facility-Wide Averaging Plan will be subject to during 
the ozone season, together with all assumptions included in such 
calculation; and
    (iv) Adequate provisions for testing, monitoring, recordkeeping, 
and reporting for each affected unit.
    (2) Upon the Administrator's approval of a proposed Facility-Wide 
Averaging Plan, the owner or operator of the affected units covered by 
the Facility-Wide Averaging Plan shall comply with the cap identified 
in the plan in lieu of the emissions limits in paragraph (c) of this 
section. You will be in compliance with the cap if the sum of 
NOX emissions from all units covered by the Facility-Wide 
Averaging Plan, in tons per day on a 30-day rolling average basis, is 
less than or equal to the cap.
    (3) The owner or operator will calculate the cap according to 
equation 1 to this paragraph (d)(3). You will monitor and record daily 
hours of engine operation for use in calculating the cap on a 30-day 
rolling average basis. You will base the hours of operation on hour 
readings from a non-resettable hour meter or an equivalent monitoring 
device.
    Equation 1 to Paragraph (d)(3)
    [GRAPHIC] [TIFF OMITTED] TR05JN23.006
    
Where:

Hi = the average daily operating hours based on the 
highest consecutive 30-day period during the ozone season of the two 
most recent years preceding the emissions averaging year (hours).
i = each affected unit included in the Cap.
N = number of affected units.
DC = the engine manufacturer's design maximum capacity in horsepower 
(hp) at the installation site conditions.
Rli = the emissions limit for each affected unit from 
paragraph (c) of this section (grams/hp-hr).

    (i) Any affected unit for which less than two years of operating 
data are available shall not be included in the Facility-Wide Averaging 
Plan unless the owner or operator extrapolates the available operating 
data for the affected unit to two years of operating data, for use in 
calculating the emissions cap in accordance with paragraph (d)(3) of 
this section.
    (ii) [Reserved]
    (4) The owner or operator of an affected units covered by an EPA-
approved Facility-Wide Averaging Plan will be in violation of the cap 
if the sum of NOX emissions from all such units, in tons per 
day on a 30-day rolling average basis, exceeds the cap. Each day of 
noncompliance by each affected unit covered by the Facility-Wide 
Averaging Plan shall be a violation of the cap until corrective action 
is taken to achieve compliance.
    (e) Testing and monitoring requirements. (1) If you are the owner 
or operator of an affected unit subject to a NOX emissions 
limit under paragraph (c) 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) If you are the owner or operator of an affected unit and are 
operating a NOX continuous emissions monitoring system 
(CEMS) that monitors NOX emissions from the affected unit, 
you may use the CEMS data in lieu of the annual performance tests and 
parametric monitoring required under this section. You must meet the 
following requirements for using CEMS to monitor NOX 
emissions:
    (i) 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).
    (ii) The CEMS shall be operated and data recorded during all 
periods of operation during the ozone season of the affected unit 
except for CEMS breakdowns and repairs. Data shall be recorded during 
calibration checks and zero and span adjustments.
    (iii) The 1-hour average NOX emissions rates measured by 
the CEMS shall be used to calculate the average emissions rates to 
demonstrate compliance with the applicable emissions limits in this 
section.
    (iv) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems.
    (v) When NOX emissions data are not obtained because of 
CEMS breakdowns, repairs, calibration checks, and zero and span 
adjustments, emissions data will be obtained by using standby

[[Page 36876]]

monitoring systems, Method 7 of 40 CFR part 60, appendix A-4, Method 7A 
of 40 CFR part 60, appendix A-4, or other approved reference methods to 
provide emissions 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.
    (3)(i) If you are the owner or operator of a new affected unit, you 
must conduct an initial performance test within six months of engine 
startup and conduct subsequent performance tests every twelve months 
thereafter to demonstrate compliance. If pollution control equipment is 
installed to comply with a NOX emissions limit in paragraph 
(c) of this section, however, the initial performance test shall be 
conducted within 90 days of such installation.
    (ii) If you are the owner or operator of an existing affected unit, 
you must conduct an initial performance test within six months of 
becoming subject to an emissions limit under paragraph (c) of this 
section and conduct subsequent performance tests every twelve months 
thereafter to demonstrate compliance. If pollution control equipment is 
installed to comply with a NOX emissions limit in paragraph 
(c) of this section, however, the initial performance test shall be 
conducted within 90 days of such installation.
    (iii) If you are the owner or operator of a new or existing 
affected unit that is only operated during peak demand periods outside 
of the ozone season and the engine's hours of operation during the 
ozone season are 50 hours or less, the affected unit is not subject to 
the testing and monitoring requirements of this paragraph (e)(3)(iii) 
as long as you record and report your hours of operation during the 
ozone season in accordance with paragraphs (f) and (g) of this section.
    (iv) If you are the owner or operator of an affected unit, you must 
conduct all performance tests consistent with the requirements of 40 
CFR 60.4244 in accordance with the applicable reference test methods 
identified in table 2 to subpart JJJJ of 40 CFR part 60, any 
alternative test method approved by the EPA as of June 5, 2023, 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 the EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other 
methods and procedures approved by the EPA through notice-and-comment 
rulemaking. To determine compliance with the NOX emissions 
limit in paragraph (c) of this section, the emissions rate shall be 
calculated in accordance with the requirements of 40 CFR 60.4244(d).
    (4) If you are the owner or operator of an affected unit that has a 
non-selective catalytic reduction (NSCR) control device to reduce 
emissions, you must:
    (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; and
    (ii) Measure the pressure drop across the catalyst monthly and 
conduct maintenance if the pressure drop across the catalyst changes by 
more than 2 inches of water at 100 percent load plus or minus 10 
percent from the pressure drop across the catalyst measured during the 
most recent performance test.
    (5) If you are the owner of operator of an affected unit not using 
an NSCR control device to reduce emissions, you are required to conduct 
continuous parametric monitoring to assure compliance with the 
applicable emissions limits according to the requirements in paragraphs 
(e)(5)(i) through (vi) of this section.
    (i) You must prepare a site-specific monitoring plan that includes 
all of the following monitoring system design, data collection, and 
quality assurance and quality control elements:
    (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 (e)(1) of this section.
    (E) Ongoing recordkeeping and reporting procedures in accordance 
with the requirements of paragraphs (f) and (g) of this section.
    (ii) You must continuously monitor the selected operating 
parameters according to the procedures in your site-specific monitoring 
plan.
    (iii) You must collect parametric monitoring data at least once 
every 15 minutes.
    (iv) When 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 performance evaluations, 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 parametric 
monitoring device in accordance with your site-specific monitoring 
plan.
    (6) If you are the owner or operator of an affected unit that is 
only operated during peak periods outside of the ozone season and your 
hours of operation during the ozone season are 0, you are not subject 
to the testing and monitoring requirements of this paragraph (e)(6) so 
long as you record and report your hours of operation during the ozone 
season in accordance with paragraphs (f) and (g) of this section.
    (f) Recordkeeping requirements. If you are the owner or operator of 
an affected unit, you must keep records of:
    (1) Performance tests conducted pursuant to paragraph (e)(2) of 
this section, including the date, engine settings on the date of the 
test, and documentation of the methods and results of the testing.
    (2) Catalyst monitoring required by paragraph (e)(3) of this 
section, 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.
    (3) Parameters monitored pursuant to the facility's site-specific 
parametric monitoring plan.
    (4) Hours of operation on a daily basis.
    (5) Tuning, adjustments, or other combustion process adjustments 
and the date of the adjustment(s).
    (6) For any Facility-Wide Averaging Plan approved by the 
Administrator under paragraph (d) of this section, daily calculations 
of total NOX emissions to demonstrate compliance with the 
cap during the ozone season. You must use the equation in this 
paragraph (f)(6) to calculate total NOX emissions from all 
affected units covered by the Facility-Wide Averaging Plan, in tons per 
day on a 30-day rolling average basis, for purposes of determining 
compliance with the cap during the ozone season. A new 30-day rolling 
average emissions rate in tpd is calculated for each operating day 
during the ozone season, using the 30-day rolling average daily 
operating hours for the preceding 30 operating days.
    Equation 2 to Paragraph (f)(6)

[[Page 36877]]

[GRAPHIC] [TIFF OMITTED] TR05JN23.007

Where:

Hai = the consecutive 30-day rolling average daily 
operating hours for the preceding 30 operating days during ozone 
season (hours).
i = each affected unit.
N = number of affected units.
DC = the engine manufacturer's maximum design capacity in horsepower 
(hp) at the installation site conditions.
Rai = the actual emissions rate for each affected unit 
based on the most recent performance test results, (grams/hp-hr).

    (g) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you must submit the results of the performance test 
or performance evaluation of the CEMS following the procedures 
specified in Sec.  52.40(g) within 60 days after completing each 
performance test required by this section.
    (2) If you are the owner or operator of an affected unit, you are 
required to submit excess emissions reports for any excess emissions 
that occurred during the reporting period. Excess emissions are defined 
as any calculated 30-day rolling average NOX emissions rate 
that exceeds the applicable emissions limit in paragraph (c) of this 
section. Excess emissions 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 following the 
procedures specified in Sec.  52.40(g).
    (3) If you are the owner or operator of an affected unit, you must 
submit an annual report in PDF format to the EPA by January 30th of 
each year via CEDRI or analogous electronic reporting approach provided 
by the EPA to report data required by this section. Annual reports 
shall be submitted following the procedures in paragraph (g) of 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 emissions limit 
under paragraph (c) of this section or a Facility-Wide Averaging Plan 
under paragraph (d) of this section;
    (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 paragraph (e) of this section;
    (viii) Any records required by paragraph (f) of this section, 
including records of parametric monitoring data, to demonstrate 
compliance with the applicable emissions limit under paragraph (c) of 
this section or a Facility-Wide Averaging Plan under paragraph (d) of 
this section, if applicable;
    (ix) If applicable, a statement documenting any change in the 
operating characteristics of the subject engine; and
    (x) A statement certifying that the information included in the 
annual report is complete and accurate.


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 in this paragraph (a) shall 
have the meaning given to them in the Act and in subpart A of 40 CFR 
part 60.
    Affected unit means a cement kiln meeting the applicability 
criteria of this section.
    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.
    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.
    Operating day means a 24-hour period beginning at 12:00 midnight 
during which the kiln produces clinker at any time.
    (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 on or after August 4, 2023, and is located within any of 
the States listed in Sec.  52.40(c)(2), including Indian country 
located within the borders of any such State(s). Any existing cement 
kiln with a potential to emit of 100 tons per year or more of 
NOX on August 4, 2023, will continue to be subject to the 
requirements of this section even if that unit later becomes subject to 
a physical or operational limitation that lowers its potential to emit 
below 100 tons per year of NOX.
    (c) Emissions limitations. If you are the owner or operator of an 
affected unit, you must meet the following emissions limitations on a 
30-day rolling average basis during the 2026 ozone season and in each 
ozone season thereafter:
    (1) Long wet kilns: 4.0 lb/ton of clinker;
    (2) Long dry kilns: 3.0 lb/ton of clinker;
    (3) Preheater kilns: 3.8 lb/ton of clinker;
    (4) Precalciner kilns: 2.3 lb/ton of clinker; and
    (5) Preheater/Precalciner kilns: 2.8 lb/ton of clinker.
    (d) Testing and monitoring requirements. (1) If you are the owner 
or operator of an affected unit you must conduct performance tests, on 
an annual basis, in accordance with the applicable reference test 
methods of 40 CFR part 60, appendix A-4, any alternative test method 
approved by the EPA as of June 5, 2023, 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 the EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods and 
procedures approved by the EPA through notice-and-comment rulemaking. 
The annual performance test does not have to be performed during the 
ozone season. You must calculate and record the 30-operating day 
rolling average emissions 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 1 to this paragraph 
(d)(1):
    Equation 1 to Paragraph (d)(1)
    [GRAPHIC] [TIFF OMITTED] TR05JN23.002
    
Where:

E30D = 30 kiln operating day average emissions 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.

[[Page 36878]]

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.

    (2) If you are the owner or operator of an affected unit and are 
operating a NOX continuous emissions monitoring system 
(CEMS) that monitors NOX emissions from the affected unit, 
you may use the CEMS data in lieu of the annual performance tests and 
parametric monitoring required under this section. You must meet the 
following requirements for using CEMS to monitor NOX 
emissions:
    (i) 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).
    (ii) The CEMS shall be operated and data recorded during all 
periods of operation during the ozone season of the affected unit 
except for CEMS breakdowns and repairs. Data shall be recorded during 
calibration checks and zero and span adjustments.
    (iii) The 1-hour average NOX emissions rates measured by 
the CEMS shall be expressed in terms of lbs/ton of clinker and shall be 
used to calculate the average emissions rates to demonstrate compliance 
with the applicable emissions limits in this section.
    (iv) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems.
    (v) When NOX emissions data are not obtained because of 
CEMS breakdowns, repairs, calibration checks and zero and span 
adjustments, emissions data will be obtained by using standby 
monitoring systems, Method 7 of 40 CFR part 60, appendix A-4, Method 7A 
of 40 CFR part 60, appendix A-4, or other approved reference methods to 
provide emissions 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.
    (3) If you are the owner or operator of an affected unit not 
operating NOX CEMS, you must conduct an initial performance 
test before the 2026 ozone season to establish appropriate indicator 
ranges for operating parameters and continuously monitor those operator 
parameters consistent with the requirements of paragraphs (d)(3)(i) 
through (v) of this section.
    (i) You must monitor and record kiln stack exhaust gas flow rate, 
hourly clinker production rate or kiln feed rate, and kiln stack 
exhaust temperature during the initial performance test and subsequent 
annual performance tests to demonstrate continuous compliance with your 
NOX emissions limits.
    (ii) You must determine hourly clinker production by one of two 
methods:
    (A) Install, calibrate, maintain, and operate a permanent weigh 
scale system to record weight rates of the amount of clinker produced 
in tons of mass per hour. The system of measuring hourly clinker 
production must be maintained within 5 percent accuracy; or
    (B) Install, calibrate, maintain, and operate a permanent weigh 
scale system to measure and record weight rates of the amount of feed 
to the kiln in tons of mass per hour. The system of measuring feed must 
be maintained within 5 percent accuracy. Calculate your 
hourly clinker production rate using a kiln specific feed-to-clinker 
ratio based on reconciled clinker production rates determined for 
accounting purposes and recorded feed rates. This ratio should be 
updated monthly. Note that if this ratio changes at clinker 
reconciliation, you must use the new ratio going forward, but you do 
not have to retroactively change clinker production rates previously 
estimated.
    (C) For each kiln operating hour for which you do not have data on 
clinker production or the amount of feed to the kiln, use the value 
from the most recent previous hour for which valid data are available.
    (D) If you measure clinker production directly, record the daily 
clinker production rates; if you measure the kiln feed rates and 
calculate clinker production, record the daily kiln feed and clinker 
production rates.
    (iii) You must use the kiln stack exhaust gas flow rate, hourly 
kiln production rate or kiln feed rate, and kiln stack exhaust 
temperature during the initial performance test and subsequent annual 
performance tests as indicators of NOX operating parameters 
to demonstrate continuous compliance and establish site-specific 
indicator ranges for these operating parameters.
    (iv) You must repeat the performance test annually to reassess and 
adjust the site-specific operating parameter indicator ranges in 
accordance with the results of the performance test.
    (v) You must report and include your ongoing site-specific 
operating parameter data in the annual reports required under paragraph 
(e) of this section and semi-annual title V monitoring reports to the 
relevant permitting authority.
    (e) Recordkeeping requirements. If you are the owner or operator of 
an affected unit, you shall maintain records of the following 
information for each day the affected unit operates:
    (1) Calendar date;
    (2) The average hourly NOX emissions rates measured or 
predicted;
    (3) The 30-day average NOX emissions rates calculated at 
the end of each affected unit operating day from the measured or 
predicted hourly NOX emissions rates for the preceding 30 
operating days;
    (4) Identification of the affected unit operating days when the 
calculated 30-day average NOX emissions rates are in excess 
of the applicable site-specific NOX emissions limit with the 
reasons for such excess emissions as well as a description of 
corrective actions taken;
    (5) 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;
    (6) Identification of the times when emissions data have been 
excluded from the calculation of average emissions rates and the 
reasons for excluding data;
    (7) If a CEMS is used to verify compliance:
    (i) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (ii) 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 to 40 CFR part 60; and
    (iii) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F;
    (8) Operating parameters required under paragraph (d) of this 
section to demonstrate compliance during the ozone season;
    (9) Each fuel type, usage, and heat content; and
    (10) Clinker production rates.
    (f) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you shall submit the results of the performance test 
or performance evaluation of the CEMS following the procedures 
specified in Sec.  52.40(g) within 60 days after the date of completing 
each performance test required by this section.
    (2) If you are the owner or operator of an affected unit, you are 
required to submit excess emissions reports for any excess emissions 
that occurred during the reporting period. Excess emissions are defined 
as any calculated 30-day rolling average NOX emissions rate 
that exceeds the applicable emissions limit established under paragraph 
(c) of this section. Excess emissions reports must

[[Page 36879]]

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 following the procedures specified in Sec.  52.40(g).
    (3) If you are the owner or operator of an affected unit, you shall 
submit an annual report in PDF format to the EPA by January 30th of 
each year via CEDRI or analogous electronic reporting approach provided 
by the EPA to report data required by this section. Annual reports 
shall be submitted following the procedures in Sec.  52.40(g). The 
report shall include records all records required by paragraph (d) of 
this section, including record of CEMS data or operating parameters 
required by paragraph (d) to demonstrate continuous compliance the 
applicable emissions limits under paragraph (c) of this section.
    (g) Initial notification requirements for existing affected units. 
(1) The requirements of this paragraph (g) apply to the owner or 
operator of an existing affected unit.
    (2) The owner or operator of an existing affected unit that emits 
or has a potential to emit 100 tons per year or greater as of August 4, 
2023, shall notify the Administrator via the CEDRI or analogous 
electronic submission system provided by the EPA that the unit is 
subject to this section. The notification, which shall be submitted not 
later than December 4, 2023, shall be submitted in PDF format to the 
EPA via CEDRI, which can be accessed through the EPA's CDX (https://cdx.epa.gov/). The notification shall provide the following 
information:
    (i) The name and address of the owner or operator;
    (ii) The address (i.e., physical location) of the affected unit;
    (iii) An identification of the relevant standard, or other 
requirement, that is the basis for the notification and the unit's 
compliance date; and
    (iv) A brief description of the nature, size, design, and method of 
operation of the facility and an identification of the types of 
emissions points (units) within the facility subject to the relevant 
standard.


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 in this paragraph (a) shall 
have the meaning given to them in the Act and in subpart A of 40 CFR 
part 60.
    Affected unit means any reheat furnace meeting the applicability 
criteria of this section.
    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.
    Low NOX burner means a burner designed to reduce flame turbulence 
by the mixing of fuel and air and by establishing fuel-rich zones for 
initial combustion, thereby reducing the formation of NOX.
    Low-NOX technology means any post-combustion NOX control 
technology capable of reducing NOX emissions by 40% from 
baseline emission levels as measured during pre-installation testing.
    Operating day means a 24-hour period beginning at 12:00 midnight 
during which any fuel is combusted at any time in the reheat furnace.
    Reheat furnace means a furnace used to heat steel product--
including metal ingots, billets, slabs, beams, blooms and other similar 
products--for the purpose of deformation and rolling.
    (b) Applicability. The requirements of this section apply to each 
new or existing reheat furnace 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 on or after August 4, 2023, 
does not have low-NOX burners installed, and is located 
within any of the States listed in Sec.  52.40(c)(2), including Indian 
country located within the borders of any such State(s). Any existing 
reheat furnace with a potential to emit of 100 tons per year or more of 
NOX on August 4, 2023, will continue to be subject to the 
requirements of this section even if that unit later becomes subject to 
a physical or operational limitation that lowers its potential to emit 
below 100 tons per year of NOX.
    (c) Emissions control requirements. If you are the owner or 
operator of an affected unit without low-NOX burners already 
installed, you must install and operate low-NOX burners or 
equivalent alternative low-NOX technology designed to 
achieve at least a 40% reduction from baseline NOX emissions 
in accordance with the work plan established pursuant to paragraph (d) 
of this section. You must meet the emissions limit established under 
paragraph (d) on a 30-day rolling average basis.
    (d) Work plan requirements. (1) The owner or operator of each 
affected unit must submit a work plan for each affected unit by August 
5, 2024. The work plan must be submitted via CEDRI or analogous 
electronic reporting approach provided by the EPA to report data 
required by this section following the procedures specified in Sec.  
52.40(g). Each work plan must include a description of the affected 
unit and rated production and energy capacities, identification of the 
low-NOX burner or alternative low NOX technology 
selected, and the phased construction timeframe by which you will 
design, install, and consistently operate the device. Each work plan 
shall also include, where applicable, performance test results obtained 
no more than five years before August 4, 2023, to be used as baseline 
emissions testing data providing the basis for required emissions 
reductions. If no such data exist, then the owner or operator must 
perform pre-installation testing as described in paragraph (e)(3) of 
this section.
    (2) The owner or operator of an affected unit shall design each 
low-NOX burner or alternative low-NOX technology 
identified in the work plan to achieve NOX emission 
reductions by a minimum of 40% from baseline emission levels measured 
during performance testing that meets the criteria set forth in 
paragraph (e)(1) of this section, or during pre-installation testing as 
described in paragraph (e)(3) of this section. Each low-NOX 
burner or alternative low-NOX technology shall be 
continuously operated during all production periods according to 
paragraph (c) of this section.
    (3) The owner or operator of an affected unit shall establish an 
emissions limit in the work plan that the affected unit must comply 
with in accordance with paragraph (c) of this section.
    (4) The EPA's action on work plans:
    (i) The Administrator will provide via the CEDRI or analogous 
electronic submission system provided by the EPA notification to the 
owner or operator of an affected unit if the submitted work plan is 
complete, that is, whether the request contains sufficient information 
to make a determination, within 60 calendar days after receipt of the 
original work plan and within 60 calendar days after receipt of any 
supplementary information.
    (ii) The Administrator will provide notification via the CEDRI or 
analogous electronic submission system provided by the EPA, which shall 
be publicly available, to the owner or operator of a decision to 
approve or intention to disapprove the work plan within 60 calendar 
days after providing written notification pursuant to paragraph

[[Page 36880]]

(d)(4)(i) of this section that the submitted work plan is complete.
    (iii) Before disapproving a work plan, the Administrator will 
notify the owner or operator via the CEDRI or analogous electronic 
submission system provided by the EPA of the Administrator's intention 
to issue the disapproval, together with:
    (A) Notice of the information and findings on which the intended 
disapproval is based; and
    (B) Notice of opportunity for the owner or operator to present in 
writing, within 15 calendar days after he/she is notified of the 
intended disapproval, additional information or arguments to the 
Administrator before further action on the work plan.
    (iv) The Administrator's final decision to disapprove a work plan 
will be via the CEDRI or analogous electronic submission system 
provided by the EPA and publicly available, and will set forth the 
specific grounds on which the disapproval is based. The final decision 
will be made within 60 calendar days after presentation of additional 
information or argument (if the submitted work plan is complete), or 
within 60 calendar days after the deadline for the submission of 
additional information or argument under paragraph (d)(5)(iii)(B) of 
this section, if no such submission is made.
    (v) If the Administrator disapproves the submitted work plan for 
failure to satisfy the requirements of paragraphs (c) and (d)(1) 
through (3) of this section, or if the owner or operator of an affected 
unit fails to submit a work plan by August 5, 2024, the owner or 
operator will be in violation of this section. Each day that the 
affected unit operates following such disapproval or failure to submit 
shall constitute a violation.
    (e) Testing and monitoring requirements. (1) If you are the owner 
or operator of an affected unit you must conduct performance tests, on 
an annual basis, in accordance with the applicable reference test 
methods of 40 CFR part 60, appendix A-4, any alternative test method 
approved by the EPA as of June 5, 2023, 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 the EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods and 
procedures approved by the EPA through notice-and-comment rulemaking. 
The annual performance test does not have to be performed during the 
ozone season.
    (2) If you are the owner or operator of an affected unit and are 
operating a NOX continuous emissions monitoring system 
(CEMS) that monitors NOX emissions from the affected unit, 
you may use the CEMS data in lieu of the annual performance tests and 
parametric monitoring required under this section. You must meet the 
following requirements for using CEMS to monitor NOX 
emissions:
    (i) 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).
    (ii) The CEMS shall be operated and data recorded during all 
periods of operation during the ozone season of the affected unit 
except for CEMS breakdowns and repairs. Data shall be recorded during 
calibration checks and zero and span adjustments.
    (iii) The 1-hour average NOX emissions rates measured by 
the CEMS shall be expressed in form of the emissions limit established 
in the work plan and shall be used to calculate the average emissions 
rates to demonstrate compliance with the applicable emissions limits 
established in the work plan.
    (iv) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems.
    (v) When NOX emissions data are not obtained because of 
CEMS breakdowns, repairs, calibration checks and zero and span 
adjustments, emissions data will be obtained by using standby 
monitoring systems, Method 7 of 40 CFR part 60, appendix A-4, Method 7A 
of 40 CFR part 60, appendix A-4, or other approved reference methods to 
provide emissions 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.
    (3) If you are the owner or operator of an affected unit not 
operating NOX CEMS, you must conduct an initial performance 
test before the 2026 ozone season to establish appropriate indicator 
ranges for operating parameters and continuously monitor those operator 
parameters consistent with the requirements of paragraphs (e)(3)(i) 
through (iv) of this section.
    (i) You must monitor and record stack exhaust gas flow rate and 
temperature during the initial performance test and subsequent annual 
performance tests to demonstrate continuous compliance with your 
NOX emissions limits.
    (ii) You must use the stack exhaust gas flow rate and temperature 
during the initial performance test and subsequent annual performance 
tests to establish a site-specific indicator for these operating 
parameters.
    (iii) You must repeat the performance test annually to reassess and 
adjust the site-specific operating parameter indicator ranges in 
accordance with the results of the performance test.
    (iv) You must report and include your ongoing site-specific 
operating parameter data in the annual reports required under paragraph 
(f) of this section and semi-annual title V monitoring reports to the 
relevant permitting authority.
    (f) Recordkeeping requirements. If you are the owner or operator of 
an affected unit, you shall maintain records of the following 
information for each day the affected unit operates:
    (1) Calendar date;
    (2) The average hourly NOX emissions rates measured or 
predicted;
    (3) The 30-day average NOX emissions rates calculated at 
the end of each affected unit operating day from the measured or 
predicted hourly NOX emissions rates for the preceding 30 
operating days;
    (4) Identification of the affected unit operating days when the 
calculated 30-day average NOX emissions rates are in excess 
of the applicable site-specific NOX emissions limit with the 
reasons for such excess emissions as well as a description of 
corrective actions taken;
    (5) 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;
    (6) Identification of the times when emissions data have been 
excluded from the calculation of average emissions rates and the 
reasons for excluding data;
    (7) If a CEMS is used to verify compliance:
    (i) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (ii) 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 to 40 CFR part 60; and
    (iii) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F;
    (8) Operating parameters required under paragraph (d) of this 
section to demonstrate compliance during the ozone season; and
    (9) Each fuel type, usage, and heat content.
    (g) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you shall submit a final report via the CEDRI or 
analogous electronic submission system provided by the EPA, by no later 
than March 30, 2026,

[[Page 36881]]

certifying that installation of each selected control device has been 
completed. You shall include in the report the dates of final 
construction and relevant performance testing, where applicable, 
demonstrating compliance with the selected emission limits pursuant to 
paragraphs (c) and (d) of this section.
    (2) If you are the owner or operator of an affected unit, you must 
submit the results of the performance test or performance evaluation of 
the CEMS following the procedures specified in Sec.  52.40(g) within 60 
days after the date of completing each performance test required by 
this section.
    (3) If you are the owner or operator of an affected unit, you are 
required to submit excess emissions reports for any excess emissions 
that occurred during the reporting period. Excess emissions are defined 
as any calculated 30-day rolling average NOX emissions rate 
that exceeds the applicable emissions limit established under 
paragraphs (c) and (d) of this section. Excess emissions 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 following the procedures specified in Sec.  52.40(g).
    (4) If you are the owner or operator of an affected unit, you shall 
submit an annual report in PDF format to the EPA by January 30th of 
each year via CEDRI or analogous electronic reporting approach provided 
by the EPA to report data required by this section. Annual reports 
shall be submitted following the procedures in Sec.  52.40(g). The 
report shall include records all records required by paragraphs (e) and 
(f) of this section, including record of CEMS data or operating 
parameters required by paragraph (e) to demonstrate compliance the 
applicable emissions limits established under paragraphs (c) and (d) of 
this section.
    (h) Initial notification requirements for existing affected units. 
(1) The requirements of this paragraph (h) apply to the owner or 
operator of an existing affected unit.
    (2) The owner or operator of an existing affected unit that emits 
or has a potential to emit 100 tons per year or more of NOX 
as of August 4, 2023, shall notify the Administrator via the CEDRI or 
analogous electronic submission system provided by the EPA that the 
unit is subject to this section. The notification, which shall be 
submitted not later than December 4, 2023, shall be submitted in PDF 
format to the EPA via CEDRI, which can be accessed through the EPA's 
CDX (https://cdx.epa.gov/). The notification shall provide the 
following information:
    (i) The name and address of the owner or operator;
    (ii) The address (i.e., physical location) of the affected unit;
    (iii) An identification of the relevant standard, or other 
requirement, that is the basis for the notification and the unit's 
compliance date; and
    (iv) A brief description of the nature, size, design, and method of 
operation of the facility and an identification of the types of 
emissions points (units) within the facility subject to the relevant 
standard.


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 in this paragraph (a) shall 
have the meaning given to them in the Act and in subpart A of 40 CFR 
part 60.
    Affected units means a glass manufacturing furnace meeting the 
applicability criteria of this section.
    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 (SIC) 
3221 (SIC 3221).
    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.
    Idling means the operation of a glass melting furnace at less than 
25% of the permitted production capacity or fuel use capacity as stated 
in the operating permit.
    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.
    Operating day means a 24-hr period beginning at 12:00 midnight 
during which the furnace combusts fuel at any time but excludes any 
period of startup, shutdown, or idling during which the affected unit 
complies with the requirements in paragraphs (d) through (f) of this 
section, as applicable.
    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.
    Shutdown means the period of time during which a glass melting 
furnace is taken from an operational to a non-operational status by 
allowing it to cool down from its operating temperature to a cold or 
ambient temperature as the fuel supply is turned off.
    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.
    Startup means the period of time, after initial construction or a 
furnace rebuild, during which a glass melting furnace is heated to 
operating temperatures by the primary furnace

[[Page 36882]]

combustion system, and systems and instrumentation are brought to 
stabilization.
    Textile fiberglass means fibrous glass in the form of continuous 
strands having uniform thickness.
    Wool fiberglass means fibrous glass of random texture, including 
accoustical board and tile (mineral wool), fiberglass insulation, glass 
wool, insulation (rock wool, fiberglass, slag, and silicia minerals), 
and mineral wool roofing mats.
    (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 on or after August 4, 2023, and is 
located within any of the States listed in Sec.  52.40(c)(2), including 
Indian country located within the borders of any such State(s). Any 
existing glass manufacturing furnace with a potential to emit of 100 
tons per year or more of NOX on August 4, 2023, will 
continue to be subject to the requirements of this section even if that 
unit later becomes subject to a physical or operational limitation that 
lowers its potential to emit below 100 tons per year of NOX.
    (c) Emissions limitations. If you are the owner or operator of an 
affected unit, you must meet the emissions limitations in paragraphs 
(c)(1) and (2) of this section on a 30-day rolling average basis during 
the 2026 ozone season and in each ozone season thereafter. For the 2026 
ozone season, the emissions limitations in paragraphs (c)(1) and (2) do 
not apply during shutdown and idling if the affected unit complies with 
the requirements in paragraphs (e) and (f) of this section, as 
applicable. For the 2027 and subsequent ozone seasons, the emissions 
limitations in paragraphs (c)(1) and (2) do not apply during startup, 
shutdown, and idling, if the affected unit complies with the 
requirements in paragraphs (d) through (f) of this section, as 
applicable.
    (1) Container glass, pressed/blown glass, or fiberglass 
manufacturing furnace: 4.0 lb/ton of glass; and
    (2) Flat glass manufacturing furnace: 7.0 lb/ton of glass.
    (d) Startup requirements. (1) If you are the owner or operator of 
an affected unit, you shall submit via the CEDRI or analogous 
electronic submission system provided by the EPA, no later than 30 days 
prior to the anticipated date of startup, the following information to 
assure proper operation of the furnace:
    (i) A detailed list of activities to be performed during startup 
and explanations to support the length of time needed to complete each 
activity.
    (ii) A description of the material process flow rates, system 
operating parameters, and other information that the owner or operator 
shall monitor and record during the startup period.
    (iii) Identification of the control technologies or strategies to 
be utilized.
    (iv) A description of the physical conditions present during 
startup periods that prevent the controls from being effective.
    (v) A reasonably precise estimate as to when physical conditions 
will have reached a state that allows for the effective control of 
emissions.
    (2) The length of startup following activation of the primary 
furnace combustion system may not exceed:
    (i) Seventy days for a container, pressed or blown glass furnace;
    (ii) Forty days for a fiberglass furnace; and
    (iii) One hundred and four days for a flat glass furnace and for 
all other glass melting furnaces not covered under paragraphs (d)(2)(i) 
and (ii) of this section.
    (3) During the startup period, the owner or operator of an affected 
unit shall maintain the stoichiometric ratio of the primary furnace 
combustion system so as not to exceed 5 percent excess oxygen, as 
calculated from the actual fuel and oxidant flow measurements for 
combustion in the affected unit.
    (4) The owner or operator of an affected unit shall place the 
emissions control system in operation as soon as technologically 
feasible during startup to minimize emissions.
    (e) Shutdown requirements. (1) If you are the owner or operator of 
an affected unit, you shall submit via the CEDRI or analogous 
electronic submission system provided by the EPA to the Administrator, 
no later than 30 days prior to the anticipated date of shutdown, the 
following information to assure proper operation of the furnace:
    (i) A detailed list of activities to be performed during shutdown 
and explanations to support the length of time needed to complete each 
activity.
    (ii) A description of the material process flow rates, system 
operating parameters, and other information that the owner or operator 
shall monitor and record during the shutdown period.
    (iii) Identification of the control technologies or strategies to 
be utilized.
    (iv) A description of the physical conditions present during 
shutdown periods that prevent the controls from being effective.
    (v) A reasonably precise estimate as to when physical conditions 
will have reached a state that allows for the effective control of 
emissions.
    (2) The duration of a shutdown, as measured from the time the 
furnace operations drop below 25% of the permitted production capacity 
or fuel use capacity to when all emissions from the furnace cease, may 
not exceed 20 days.
    (3) If you are the owner or operator of an affected unit, you shall 
operate the emissions control system whenever technologically feasible 
during shutdown to minimize emissions.
    (f) Idling requirements. (1) If you are the owner or operator of an 
affected unit, you shall operate the emissions control system whenever 
technologically feasible during idling to minimize emissions.
    (2) If you are the owner or operator of an affected unit, your 
NOX emissions during idling may not exceed the amount 
calculated using the following equation: Pounds per day emissions limit 
of NOX = (Applicable NOX emissions limit 
specified in paragraph (c) of this section expressed in pounds per ton 
of glass produced) x (Furnace permitted production capacity in tons of 
glass produced per day).
    (3) To demonstrate compliance with the alternative daily 
NOX emissions limit identified in paragraph (f)(2) of this 
section during periods of idling, the owners or operators of an 
affected unit shall maintain records consistent with paragraph (h)(3) 
of this section.
    (g) Testing and monitoring requirements. (1) If you own or operate 
an affected unit subject to the NOX emissions limits under 
paragraph (c) of this section you must conduct performance tests, on an 
annual basis, in accordance with the applicable reference test methods 
of 40 CFR part 60, appendix A-4, any alternative test method approved 
by the EPA as of June 5, 2023, 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 the 
EPA's website (https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods), or other methods and procedures approved by 
the EPA through notice-and-comment rulemaking. The annual performance 
test does not have to be performed during the ozone season. Owners or 
operators of affected units must calculate and record the 30-day 
rolling average emissions rate of NOX as the total of all 
hourly emissions data for an affected unit in the preceding 30 days, 
divided by the total tons of glass produced in that affected unit 
during the same 30-day period. Direct measurement or material balance 
using good engineering practice shall be used to determine the amount 
of glass produced during the performance test.

[[Page 36883]]

The rate of glass produced is defined as the weight of glass pulled 
from the affected unit during the performance test divided by the 
number of hours taken to perform the performance test.
    (2) If you are the owner or operator of an affected unit subject to 
the NOX emissions limits under paragraph (c)(1) of this 
section and are operating a NOX CEMS that monitors 
NOX emissions from the affected unit, you may use the CEMS 
data in lieu of the annual performance tests and parametric monitoring 
required under this section. You must meet the following requirements 
for using CEMS to monitor NOX emissions:
    (i) 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).
    (ii) The CEMS shall be operated and data recorded during all 
periods of operation during the ozone season of the affected unit 
except for CEMS breakdowns and repairs. Data shall be recorded during 
calibration checks and zero and span adjustments.
    (iii) The 1-hour average NOX emissions rates measured by 
the CEMS shall be expressed in terms of lbs/ton of glass and shall be 
used to calculate the average emissions rates to demonstrate compliance 
with the applicable emissions limits in this section.
    (iv) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the continuous monitoring 
systems.
    (v) When NOX emissions data are not obtained because of 
CEMS breakdowns, repairs, calibration checks and zero and span 
adjustments, emissions data will be obtained by using standby 
monitoring systems, Method 7 of 40 CFR part 60, appendix A-4, Method 7A 
of 40 CFR part 60, appendix A-4, or other approved reference methods to 
provide emissions 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.
    (3) If you are the owner or operator of an affected unit not 
operating NOX CEMS, you must conduct an initial performance 
test before the 2026 ozone season to establish appropriate indicator 
ranges for operating parameters and continuously monitor those operator 
parameters consistent with the requirements of paragraphs (g)(3)(i) 
through (iv) of this section.
    (i) You must monitor and record stack exhaust gas flow rate, hourly 
glass production, and stack exhaust gas temperature during the initial 
performance test and subsequent annual performance tests to demonstrate 
continuous compliance with your NOX emissions limits.
    (ii) You must use the stack exhaust gas flow rate, hourly glass 
production, and stack exhaust gas temperature during the initial 
performance test and subsequent annual performance tests as 
NOX CEMS indicators to demonstrate continuous compliance and 
establish a site-specific indicator ranges for these operating 
parameters.
    (iii) You must repeat the performance test annually to reassess and 
adjust the site-specific operating parameter indicator ranges in 
accordance with the results of the performance test.
    (iv) You must report and include your ongoing site-specific 
operating parameter data in the annual reports required under paragraph 
(h) of this section and semi-annual title V monitoring reports to the 
relevant permitting authority.
    (4) If you are the owner or operator of an affected unit seeking to 
comply with the requirements for startup under paragraph (d) of this 
section or shutdown under paragraph (e) of this section in lieu of the 
applicable emissions limit under paragraph (c) of this section, you 
must monitor material process flow rates, fuel throughput, oxidant flow 
rate, and the selected system operating parameters in accordance with 
paragraphs (d)(1)(ii) and (e)(1)(ii) of this section.
    (h) Recordkeeping requirements. (1) If you are the owner or 
operator of an affected unit, you shall maintain records of the 
following information for each day the affected unit operates:
    (i) Calendar date;
    (ii) The average hourly NOX emissions rates measured or 
predicted;
    (iii) The 30-day average NOX emissions rates calculated 
at the end of each affected unit operating day from the measured or 
predicted hourly NOX emissions rates for the preceding 30 
operating days;
    (iv) Identification of the affected unit operating days when the 
calculated 30-day average NOX emissions rates are in excess 
of the applicable site-specific NOX emissions limit 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 emissions data have been 
excluded from the calculation of average emissions rates and the 
reasons for excluding data;
    (vii) If a CEMS is used to verify compliance:
    (A) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS;
    (B) 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 to 40 CFR part 60; and
    (C) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F;
    (D) Operating parameters required under paragraph (g) to 
demonstrate compliance during the ozone season;
    (viii) Each fuel type, usage, and heat content; and
    (ix) Glass production rate.
    (2) If you are the owner or operator of an affected unit, you shall 
maintain all records necessary to demonstrate compliance with the 
startup and shutdown requirements in paragraphs (d) and (e) of this 
section, including but not limited to records of material process flow 
rates, system operating parameters, the duration of each startup and 
shutdown period, fuel throughput, oxidant flow rate, and any additional 
records necessary to determine whether the stoichiometric ratio of the 
primary furnace combustion system exceeded 5 percent excess oxygen 
during startup.
    (3) If you are the owner or operator of an affected unit, you shall 
maintain records of daily NOX emissions in pounds per day 
for purposes of determining compliance with the applicable emissions 
limit for idling periods under paragraph (f)(2) of this section. Each 
owner or operator shall also record the duration of each idling period.
    (i) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you must submit the results of the performance test 
or performance evaluation of the CEMS following the procedures 
specified in Sec.  52.40(g) within 60 days after the date of completing 
each performance test required by this section.
    (2) If you are the owner or operator of an affected unit, you are 
required to submit excess emissions reports for any excess emissions 
that occurred during the reporting period. Excess emissions are defined 
as any calculated 30-day rolling average NOX emissions rate 
that exceeds the applicable emissions limit in paragraph (c) of this 
section. Excess emissions 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 following the 
procedures specified in Sec.  52.40(g).

[[Page 36884]]

    (3) If you own or operate an affected unit, you shall submit an 
annual report in PDF format to the EPA by January 30th of each year via 
CEDRI or analogous electronic reporting approach provided by the EPA to 
report data required by this section. Annual reports shall be submitted 
following the procedures in Sec.  52.40(g). The report shall include 
records all records required by paragraph (g) of this section, 
including record of CEMS data or operating parameters to demonstrate 
continuous compliance the applicable emissions limits under paragraphs 
(c) of this section.
    (j) Initial notification requirements for existing affected units. 
(1) The requirements of this paragraph (j) apply to the owner or 
operator of an existing affected unit.
    (2) The owner or operator of an existing affected unit that emits 
or has a potential to emit greater than 100 tons per year or greater as 
of August 4, 2023, shall notify the Administrator via the CEDRI or 
analogous electronic submission system provided by the EPA that the 
unit is subject to this section. The notification, which shall be 
submitted not later than June 23, 2023, shall be submitted in PDF 
format to the EPA via CEDRI, which can be accessed through the EPA's 
CDX (https://cdx.epa.gov/). The notification shall provide the 
following information:
    (i) The name and address of the owner or operator;
    (ii) The address (i.e., physical location) of the affected unit;
    (iii) An identification of the relevant standard, or other 
requirement, that is the basis for the notification and the unit's 
compliance date; and
    (iv) A brief description of the nature, size, design, and method of 
operation of the facility and an identification of the types of 
emissions points (units) within the facility subject to the relevant 
standard.


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, the Pulp, Paper, and Paperboard Mills Industries, Metal 
Ore Mining, and the Iron and Steel and Ferroalloy Manufacturing 
Industries?

    (a) Definitions. All terms not defined in this paragraph (a) shall 
have the meaning given to 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.
    Boiler means an enclosed device using controlled flame combustion 
and having the primary purpose of recovering thermal energy in the form 
of steam or hot water. Controlled flame combustion refers to a steady-
state, or near steady-state, process wherein fuel and/or oxidizer feed 
rates are controlled.
    Coal means ``coal'' as defined in 40 CFR 60.41b.
    Distillate oil means ``distillate oil'' as defined in 40 CFR 
60.41b.
    Maximum heat input capacity means means the ability of a steam 
generating unit to combust a stated maximum amount of fuel on a steady 
state basis, as determined by the physical design and characteristics 
of the steam generating unit.
    Natural gas means ``natural gas'' as defined in 40 CFR 60.41.
    Operating day means a 24-hour period between 12:00 midnight and the 
following midnight during which any fuel is combusted at any time in 
the steam generating unit. It is not necessary for fuel to be combusted 
continuously for the entire 24-hour period.
    Residual oil means ``residual oil'' as defined in 40 CFR 60.41c.
    (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 that receives 90% or more of its heat input from coal, residual 
oil, distillate oil, natural gas, or combinations of these fuels in the 
previous ozone season, is located at sources that are within the Basic 
Chemical Manufacturing industry, the Petroleum and Coal Products 
Manufacturing industry, the Pulp, Paper, and Paperboard industry, the 
Metal Ore Mining industry, and the Iron and Steel and Ferroalloys 
Manufacturing industry and which is located within any of the States 
listed in Sec.  52.40(c)(2), including Indian country located within 
the borders of any such State(s). The requirements of this section do 
not apply to an emissions unit that meets the requirements for a low-
use exemption as provided in paragraph (b)(2) of this section.
    (2) If you are the owner or operator of a boiler meeting the 
applicability criteria of paragraph (b)(1) of this section that 
operates less than 10% per year on an hourly basis, based on the three 
most recent years of use and no more than 20% in any one of the three 
years, you are exempt from meeting the emissions limits of this section 
and are only subject to the recordkeeping and reporting requirements of 
paragraph (f)(2) of this section.
    (i) If you are the owner or operator of an affected unit that 
exceeds the 10% per year hour of operation over three years or the 20% 
hours of operation per year criteria, you can no longer comply via the 
low-use exemption provisions and must meet the applicable emissions 
limits and other applicable provisions as soon as possible but not 
later than one year from the date eligibility as a low-use boiler was 
negated by exceedance of the low-use boiler criteria.
    (ii) [Reserved]
    (c) Emissions limitations. If you are the owner or operator of an 
affected unit, you must meet the following emissions limitations on a 
30-day rolling average basis during the 2026 ozone season and in each 
ozone season thereafter:
    (1) Coal-fired industrial boilers: 0.20 lbs NOX/mmBtu;
    (2) Residual oil-fired industrial boilers: 0.20 lbs NOX/
mmBtu;
    (3) Distillate oil-fired industrial boilers: 0.12 lbs 
NOX/mmBtu;
    (4) Natural gas-fired industrial boilers: 0.08 lbs NOX/
mmBtu; and
    (5) Boilers using combinations of fuels listed in paragraphs (c)(1) 
through (4) of this section: such units shall comply with a 
NOX emissions limit derived by summing the products of each 
fuel's heat input and respective emissions limit and dividing by the 
sum of the heat input contributed by each fuel.
    (d) Testing and monitoring requirements. (1) If you are the owner 
or operator of an affected unit, you shall conduct an initial 
compliance test as described in 40 CFR 60.8 using the continuous system 
for monitoring NOX specified by EPA Test Method 7E of 40 CFR 
part 60, appendix A-4, to determine compliance with the emissions 
limits for NOX identified in paragraph (c) of this section. 
In lieu of the timing of the compliance test described in 40 CFR 
60.8(a), you shall conduct the test within 90 days from the 
installation of the pollution control equipment used to comply with the 
NOX emissions limits in paragraph (c) of this section and no 
later than May 1, 2026.
    (i) For the initial compliance test, you shall monitor 
NOX emissions from the affected unit for 30 successive 
operating days and the 30-day average emissions rate will be used to 
determine compliance with the NOX emissions limits in 
paragraph (c) of this section. You shall calculate the 30-day average 
emission rate as the average of all hourly emissions data recorded by 
the monitoring system during the 30-day test period.
    (ii) You are not required to conduct an initial compliance test if 
the affected unit is subject to a pre-existing, federally enforceable 
requirement to monitor its NOX emissions using a

[[Page 36885]]

CEMS in accordance with 40 CFR 60.13 or 40 CFR part 75.
    (2) If you are the owner or operator of an affected unit with a 
heat input capacity of 250 mmBTU/hr or greater, you are subject to the 
following monitoring requirements:
    (i) 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 you to use an alternative monitoring technique under 
paragraph (d)(2)(vii) of this section. If you have previously installed 
a NOX emissions rate CEMS to meet the requirements of 40 CFR 
60.13 or 40 CFR part 75 and continue to meet the ongoing requirements 
of 40 CFR 60.13 or 40 CFR part 75, that CEMS may be used to meet the 
monitoring requirements of this section.
    (ii) You shall operate the CEMS and record data during all periods 
of operation during the ozone season of the affected unit except for 
CEMS breakdowns and repairs. You shall record data during calibration 
checks and zero and span adjustments.
    (iii) You shall express the 1-hour average NOX emissions 
rates measured by the CEMS in terms of lbs/mmBtu heat input and shall 
be used to calculate the average emissions rates under paragraph (c) of 
this section.
    (iv) Following the date on which the initial compliance test is 
completed, you shall determine compliance with the applicable 
NOX emissions limit in paragraph (c) of this section during 
the ozone season on a continuous basis using a 30-day rolling average 
emissions rate unless you monitor emissions by means of an alternative 
monitoring procedure approved pursuant to paragraph (d)(2)(vii) of this 
section. You shall calculate a new 30-day rolling average emissions 
rate for each operating day as the average of all the hourly 
NOX emissions data for the preceding 30 operating days.
    (v) You shall follow the procedures under 40 CFR 60.13 for 
installation, evaluation, and operation of the continuous monitoring 
systems. Additionally, you shall use a span value of 1000 ppm 
NOX for affected units combusting coal and span value of 500 
ppm NOX for units combusting oil or gas. As an alternative 
to meeting these span values, you may elect to use the NOX 
span values determined according to section 2.1.2 in appendix A to 40 
CFR part 75.
    (vi) When you are unable to obtain NOX emissions data 
because of CEMS breakdowns, repairs, calibration checks and zero and 
span adjustments, you will obtain emissions data by using standby 
monitoring systems, Method 7 of 40 CFR part 60, appendix A-4, Method 7A 
of 40 CFR part 60, appendix A-4, or other approved reference methods to 
provide emissions 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.
    (vii) You may delay installing a CEMS for NOX 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 emissions 
limit in paragraph (c) of this section, you are not required to install 
a CEMS for measuring NOX. If you demonstrate your affected 
unit emits less than 70 percent of the applicable emissions 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 emissions 
limit(s) in paragraph (c) of this section. The Administrator may 
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.
    (3) If you are the owner or operator of an affected unit with a 
heat input capacity less than 250 mmBTU/hr, you must monitor 
NOX emission via the requirements of paragraph (e)(1) of 
this section or you must monitor NOX emissions by conducting 
an annual test in conjunction with the implementation of a monitoring 
plan meeting the following requirements:
    (i) You must conduct an initial performance test over a minimum of 
24 consecutive steam generating unit operating hours at maximum heat 
input capacity to demonstrate compliance with the NOX 
emission standards under paragraph (c) of this section using Method 7, 
7A, or 7E of appendix A-4 to 40 CFR part 60, Method 320 of appendix A 
to 40 CFR part 63, or other approved reference methods.
    (ii) You must conduct annual performance tests once per calendar 
year to demonstrate compliance with the NOX emission 
standards under paragraph (c) of this section over a minimum of 3 
consecutive steam generating unit operating hours at maximum heat input 
capacity using Method 7, 7A, or 7E of appendix A-4 to 40 CFR part 60, 
Method 320 of appendix A to 40 CFR part 63, or other approved reference 
methods. The annual performance test must be conducted before the 
affected units operates more than 400 hours in a given year.
    (iii) You must develop and comply with a monitoring plan that 
relates the operational parameters to emissions of the affected unit. 
The owner or operator of each affected unit shall develop a monitoring 
plan that identifies the operating conditions of the affected unit to 
be monitored and the records to be maintained in order to reliably 
predict NOX emissions and determine compliance with the 
applicable emissions limits of this section on a continuous basis. You 
shall include the following information in the plan:
    (A) You shall identify the specific operating parameters to be 
monitored and the relationship between these operating parameters and 
the applicable NOX emission rates. Operating parameters of 
the affected unit include, but are not limited to, the degree of staged 
combustion (i.e., the ratio of primary air to secondary and/or tertiary 
air) and the level of excess air (i.e., flue gas O2 level).
    (B) You shall include the data and information used to identify the 
relationship between NOX emission rates and these operating 
conditions.
    (C) You shall identify: how these operating parameters, including 
steam generating unit load, will be monitored on an hourly basis during 
periods of operation of the affected unit; the quality assurance 
procedures or practices that will be employed to ensure that the data 
generated by monitoring these operating parameters will be 
representative and accurate; and the type and format of the records of 
these operating parameters, including steam generating unit load, that 
you will maintain.
    (4) You shall submit the monitoring plan to the EPA via the CEDRI 
reporting system, and request that the relevant permitting agency 
incorporate the monitoring plan into the facility's title V permit.
    (e) Recordkeeping requirements. (1) If you are the owner or 
operator of an affected unit, which is not a low-use boiler, you shall 
maintain records of the following information for each day the affected 
unit operates during the ozone season:
    (i) Calendar date;
    (ii) The average hourly NOX emissions rates (expressed 
as lbs NO2/mmBtu heat input) measured or predicted;
    (iii) The 30-day average NOX emissions rates calculated 
at the end of

[[Page 36886]]

each affected unit operating day from the measured or predicted hourly 
NOX emissions rates for the preceding 30 steam generating 
unit operating days;
    (iv) Identification of the affected unit operating days when the 
calculated 30-day rolling average NOX emissions rates are in 
excess of the applicable NOX emissions 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 emissions data have been 
excluded from the calculation of average emissions 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 to 40 CFR part 60;
    (x) Results of daily CEMS drift tests and quarterly accuracy 
assessments as required under Procedure 1 of 40 CFR part 60, appendix 
F; and
    (xi) The type and amounts of each fuel combusted.
    (2) If you are the owner or operator of an affected unit complying 
as a low-use boiler, you must maintain the following records consistent 
with the requirements of Sec.  52.40(g):
    (i) Identification and location of the boiler;
    (ii) Nameplate capacity;
    (iii) The fuel or fuels used by the boiler;
    (iv) For each operating day, the type and amount of fuel combusted, 
and the date and total number of hours of operation; and
    (v) the annual hours of operation for each of the prior 3 years, 
and the 3-year average hours or operation.
    (f) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you must submit the results of the performance test 
or performance evaluation of the CEMS following the procedures 
specified in Sec.  52.40(g) within 60 days after the date of completing 
each performance test required by this section.
    (2) If you are the owner or operator of an affected unit, you are 
required to submit excess emissions reports for any excess emissions 
that occurred during the reporting period. Excess emissions are defined 
as any calculated 30-day rolling average NOX emissions rate, 
as determined under paragraph (e)(1)(iii) of this section, that exceeds 
the applicable emissions limit in paragraph (c) of this section. Excess 
emissions 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 following the procedures specified 
in Sec.  52.40(g).
    (3) If you are the owner or operator 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) of this section as described 
in paragraph (e)(1) of this section. You shall submit compliance 
reports for continuous monitoring in PDF format to the EPA via CEDRI or 
analogous electronic reporting approach provided by the EPA to report 
data required by this section following the procedures specified in 
Sec.  52.40(g).
    (4) If you are the owner or operator of an affected unit, you shall 
submit an annual report in PDF format to the EPA by January 30th of 
each year via CEDRI or analogous electronic reporting approach provided 
by the EPA to report data required by this section. Annual reports 
shall be submitted following the procedures in Sec.  52.40(g).


Sec.  52.46  What are the requirements of the Federal Implementation 
Plans (FIPs) relating to ozone season emissions of nitrogen oxides from 
Municipal Waste Combustors?

    (a) Definitions. All terms not defined in this paragraph (a) shall 
have the meaning given them in the Act and in subpart A of 40 CFR part 
60.
    Affected unit means a municipal waste combustor meeting the 
applicability criteria of this section.
    Chief facility operator means the person in direct charge and 
control of the operation of a municipal waste combustor and who is 
responsible for daily onsite supervision, technical direction, 
management, and overall performance of the facility.
    Mass burn refractory municipal waste combustor means a field-
erected combustor that combusts municipal solid waste in a refractory 
wall furnace. Unless otherwise specified, this includes combustors with 
a cylindrical rotary refractory wall furnace.
    Mass burn rotary waterwall municipal waste combustor means a field-
erected combustor that combusts municipal solid waste in a cylindrical 
rotary waterwall furnace or on a tumbling-tile grate.
    Mass burn waterwall municipal waste combustor means a field-erected 
combustor that combusts municipal solid waste in a waterwall furnace.
    Municipal waste combustor, MWC, or municipal waste combustor unit 
means:
    (i) Means any setting or equipment that combusts solid, liquid, or 
gasified MSW including, but not limited to, field-erected incinerators 
(with or without heat recovery), modular incinerators (starved-air or 
excess-air), boilers (i.e., steam-generating units), furnaces (whether 
suspension-fired, grate-fired, mass-fired, air curtain incinerators, or 
fluidized bed-fired), and pyrolysis/combustion units. Municipal waste 
combustors do not include pyrolysis/combustion units located at 
plastics/rubber recycling units. Municipal waste combustors do not 
include internal combustion engines, gas turbines, or other combustion 
devices that combust landfill gases collected by landfill gas 
collection systems.
    (ii) The boundaries of a MWC are defined as follows. The MWC unit 
includes, but is not limited to, the MSW fuel feed system, grate 
system, flue gas system, bottom ash system, and the combustor water 
system. The MWC boundary starts at the MSW pit or hopper and extends 
through:
    (A) The combustor flue gas system, which ends immediately following 
the heat recovery equipment or, if there is no heat recovery equipment, 
immediately following the combustion chamber;
    (B) The combustor bottom ash system, which ends at the truck 
loading station or similar ash handling equipment that transfer the ash 
to final disposal, including all ash handling systems that are 
connected to the bottom ash handling system; and
    (C) The combustor water system, which starts at the feed water pump 
and ends at the piping exiting the steam drum or superheater.
    (iii) The MWC unit does not include air pollution control 
equipment, the stack, water treatment equipment, or the turbine 
generator set.
    Municipal waste combustor unit capacity means the maximum charging 
rate of a municipal waste combustor unit expressed in tons per day of 
municipal solid waste combusted, calculated according to the procedures 
under paragraph (e)(4) of this section.
    Shift supervisor means the person who is in direct charge and 
control of the operation of a municipal waste combustor and who is 
responsible for onsite supervision, technical direction,

[[Page 36887]]

management, and overall performance of the facility during an assigned 
shift.
    (b) Applicability. The requirements of this section apply to each 
new or existing municipal waste combustor unit with a combustion 
capacity greater than 250 tons per day (225 megagrams per day) of 
municipal solid waste and which is located within any of the States 
listed in Sec.  52.40(c)(2), including Indian country located within 
the borders of any such State(s).
    (c) Emissions limitations. If you are the owner or operator of an 
affected unit, you must meet the following emissions limitations at all 
times, except during startup and shutdown, on a 30-day rolling average 
basis during the 2026 ozone season and in each ozone season thereafter:
    (1) 110 ppmvd at 7 percent oxygen on a 24-hour block averaging 
period; and
    (2) 105 ppmvd at 7 percent oxygen on a 30-day rolling averaging 
period.
    (d) Startup and shutdown requirements. If you are the owner or 
operator of an affected unit, you must comply with the following 
requirements during startup and shutdown:
    (1) During periods of startup and shutdown, you shall meet the 
following emissions limits at stack oxygen content:
    (i) 110 ppmvd at stack oxygen content on a 24-hour block averaging 
period; and
    (ii) 105 ppmvd at stack oxygen content on a 30-day rolling 
averaging period.
    (2) Duration of startup and shutdown, periods are limited to 3 
hours per occurrence.
    (3) The startup period commences when the affected unit begins the 
continuous burning of municipal solid waste and does not include any 
warmup period when the affected unit is combusting fossil fuel or other 
nonmunicipal solid waste fuel, and no municipal solid waste is being 
fed to the combustor.
    (4) Continuous burning is the continuous, semicontinuous, or batch 
feeding of municipal solid waste for purposes of waste disposal, energy 
production, or providing heat to the combustion system in preparation 
for waste disposal or energy production. The use of municipal solid 
waste solely to provide thermal protection of the grate or hearth 
during the startup period when municipal solid waste is not being fed 
to the grate is not considered to be continuous burning.
    (5) The owner and operator of an affected unit shall minimize 
NOX emissions by operating and optimizing the use of all 
installed pollution control technology and combustion controls 
consistent with the technological limitations, manufacturers' 
specifications, good engineering and maintenance practices, and good 
air pollution control practices for minimizing emissions (as defined in 
40 CFR 60.11(d)) for such equipment and the unit at all times the unit 
is in operation.
    (e) Testing and monitoring requirements. (1) If you are the owner 
or operator of an affected unit, you shall install, calibrate, 
maintain, and operate a continuous emissions monitoring system (CEMS) 
for measuring the oxygen or carbon dioxide content of the flue gas at 
each location where NOX are monitored and record the output 
of the system. You shall comply with the following test procedures and 
test methods:
    (i) You shall use a span value of 25 percent oxygen for the oxygen 
monitor or 20 percent carbon dioxide for the carbon dioxide monitor;
    (ii) You shall install, evaluate, and operate the CEMS in 
accordance with 40 CFR 60.13;
    (iii) You shall complete the initial performance evaluation no 
later than 180 days after the date of initial startup of the affected 
unit, as specified under 40 CFR 60.8;
    (iv) You shall operate the monitor in conformance with Performance 
Specification 3 in 40 CFR part 60, appendix B, except for section 2.3 
(relative accuracy requirement);
    (v) You shall operate the monitor in accordance with the quality 
assurance procedures of 40 CFR part 60, appendix F, except for section 
5.1.1 (relative accuracy test audit); and
    (vi) If you select carbon dioxide for use in diluent corrections, 
you shall establish the relationship between oxygen and carbon dioxide 
levels during the initial performance test according to the following 
procedures and methods:
    (A) This relationship may be reestablished during performance 
compliance tests; and
    (B) You shall submit the relationship between carbon dioxide and 
oxygen concentrations to the EPA as part of the initial performance 
test report and as part of the annual test report if the relationship 
is reestablished during the annual performance test.
    (2) If you are the owner or operator of an affected unit, you shall 
use the following procedures and test methods to determine compliance 
with the NOX emission limits in paragraph (c) of this 
section:
    (i) If you are not already operating a CEMS in accordance with 40 
CFR 60.13, you shall conduct an initial performance test for nitrogen 
oxides consistent with 40 CFR 60.8.
    (ii) You shall install and operate the NOX CEMS 
according to Performance Specification 2 in 40 CFR part 60, appendix B, 
and shall follow the requirements of 40 CFR 60.58b(h)(10).
    (iii) Quarterly accuracy determinations and daily calibration drift 
tests for the CEMS shall be performed in accordance with Procedure 1 in 
40 CFR part 60, appendix F.
    (iv) When NOX continuous emissions data are not obtained 
because of CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments, emissions data shall be obtained using other 
monitoring systems as approved by the EPA or EPA Reference Method 19 in 
40 CFR part 60, appendix A-7, to provide, as necessary, valid emissions 
data for a minimum of 90 percent of the hours per calendar quarter and 
95 percent of the hours per calendar year the unit is operated and 
combusting municipal solid waste.
    (v) You shall use EPA Reference Method 19, section 4.1, in 40 CFR 
part 60, appendix A-7, for determining the daily arithmetic average 
NOX emissions concentration.
    (A) You may request that compliance with the NOX 
emissions limit be determined using carbon dioxide measurements 
corrected to an equivalent of 7 percent oxygen. The relationship 
between oxygen and carbon dioxide levels for the affected unit shall be 
established as specified in paragraph (e)(1)(vi) of this section.
    (B) [Reserved]
    (vi) At a minimum, you shall obtain valid CEMS hourly averages for 
90 percent of the operating hours per calendar quarter and for 95 
percent of the operating hours per calendar year that the affected unit 
is combusting municipal solid waste:
    (A) At least 2 data points per hour shall be used to calculate each 
1-hour arithmetic average.
    (B) Each NOX 1-hour arithmetic average shall be 
corrected to 7 percent oxygen on an hourly basis using the 1-hour 
arithmetic average of the oxygen (or carbon dioxide) continuous 
emissions monitoring system data.
    (vii) The 1-hour arithmetic averages section shall be expressed in 
parts per million by volume (dry basis) and used to calculate the 24-
hour daily arithmetic average concentrations. The 1-hour arithmetic 
averages shall be calculated using the data points required under 40 
CFR 60.13(e)(2).
    (viii) All valid CEMS data must be used in calculating emissions 
averages even if the minimum CEMS data

[[Page 36888]]

requirements of paragraph (e)(2)(iv) of this section are not met.
    (ix) The procedures under 40 CFR 60.13 shall be followed for 
installation, evaluation, and operation of the CEMS. The initial 
performance evaluation shall be completed no later than 180 days after 
the date of initial startup of the municipal waste combustor unit.
    (3) If you are the owner or operator of an affected unit, you must 
determine compliance with the startup and shutdown requirements of 
paragraph (d) of this section by following the requirements in 
paragraphs (e)(3)(i) and (ii) of this section:
    (i) You can measure CEMS data at stack oxygen content. You can 
dismiss or exclude CEMS data from compliance calculations, but you 
shall record and report CEMS data in accordance with the provisions of 
40 CFR 60.59b(d)(7).
    (ii) You shall determine compliance with the NOX mass 
loading emissions limitation for periods of startup and shutdown by 
calculating the 24-hour average of all hourly average NOX 
emissions concentrations from continuous emissions monitoring systems.
    (A) You shall perform this calculations using stack flow rates 
derived from flow monitors, for all the hours during the 3-hour startup 
or shutdown period and the remaining 21 hours of the 24-hour period.
    (B) [Reserved]
    (4) If you are the owner or operator of an affected unit, you shall 
calculate municipal waste combustor unit capacity using the following 
procedures:
    (i) For municipal waste combustor units capable of combusting 
municipal solid waste continuously for a 24-hour period, municipal 
waste combustor unit capacity shall be calculated based on 24 hours of 
operation at the maximum charging rate. The maximum charging rate shall 
be determined as specified in paragraphs (e)(4)(i)(A) and (B) of this 
section as applicable.
    (A) For combustors that are designed based on heat capacity, the 
maximum charging rate shall be calculated based on the maximum design 
heat input capacity of the unit and a heating value of 12,800 
kilojoules per kilogram for combustors firing refuse-derived fuel and a 
heating value of 10,500 kilojoules per kilogram for combustors firing 
municipal solid waste that is not refuse-derived fuel.
    (B) For combustors that are not designed based on heat capacity, 
the maximum charging rate shall be the maximum design charging rate.
    (ii) For batch feed municipal waste combustor units, municipal 
waste combustor unit capacity shall be calculated as the maximum design 
amount of municipal solid waste that can be charged per batch 
multiplied by the maximum number of batches that could be processed in 
a 24-hour period. The maximum number of batches that could be processed 
in a 24-hour period is calculated as 24 hours divided by the design 
number of hours required to process one batch of municipal solid waste, 
and may include fractional batches (e.g., if one batch requires 16 
hours, then 24/16, or 1.5 batches, could be combusted in a 24-hour 
period). For batch combustors that are designed based on heat capacity, 
the design heating value of 12,800 kilojoules per kilogram for 
combustors firing refuse-derived fuel and a heating value of 10,500 
kilojoules per kilogram for combustors firing municipal solid waste 
that is not refuse-derived fuel shall be used in calculating the 
municipal waste combustor unit capacity in megagrams per day of 
municipal solid waste.
    (f) Recordkeeping requirements. If you are the owner or operator of 
an affected unit, you shall maintain records of the following 
information, as applicable, for each affected unit consistent with the 
requirements of Sec.  52.40(g).
    (1) The calendar date of each record.
    (2) The emissions concentrations and parameters measured using 
continuous monitoring systems.
    (i) All 1-hour average NOX emissions concentrations.
    (ii) The average concentrations and percent reductions, as 
applicable, including all 24-hour daily arithmetic average 
NOX emissions concentrations.
    (3) Identification of the calendar dates and times (hours) for 
which valid hourly NOX emissions, including reasons for not 
obtaining the data and a description of corrective actions taken.
    (4) Identification of each occurrence that NOX emissions 
data, or operational data (i.e., unit load) have been excluded from the 
calculation of average emissions concentrations or parameters, and the 
reasons for excluding the data.
    (5) The results of daily drift tests and quarterly accuracy 
determinations for CEMS, as required under 40 CFR part 60, appendix F, 
Procedure 1.
    (6) The following records:
    (i) Records showing the names of the municipal waste combustor 
chief facility operator, shift supervisors, and control room operators 
who have been provisionally certified by the American Society of 
Mechanical Engineers or an equivalent State-approved certification 
program as required by 40 CFR 60.54b(a) including the dates of initial 
and renewal certifications and documentation of current certification;
    (ii) Records showing the names of the municipal waste combustor 
chief facility operator, shift supervisors, and control room operators 
who have been fully certified by the American Society of Mechanical 
Engineers or an equivalent State-approved certification program as 
required by 40 CFR 60.54b(b) including the dates of initial and renewal 
certifications and documentation of current certification;
    (iii) Records showing the names of the municipal waste combustor 
chief facility operator, shift supervisors, and control room operators 
who have completed the EPA municipal waste combustor operator training 
course or a State-approved equivalent course as required by 40 CFR 
60.54b(d) including documentation of training completion; and
    (iv) Records of when a certified operator is temporarily off site. 
Include two main items:
    (A) If the certified chief facility operator and certified shift 
supervisor are off site for more than 12 hours, but for 2 weeks or 
less, and no other certified operator is on site, record the dates that 
the certified chief facility operator and certified shift supervisor 
were off site.
    (B) When all certified chief facility operators and certified shift 
supervisors are off site for more than 2 weeks and no other certified 
operator is on site, keep records of four items:
    (1) Time of day that all certified persons are off site.
    (2) The conditions that cause those people to be off site.
    (3) The corrective actions taken by the owner or operator of the 
affected unit to ensure a certified chief facility operator or 
certified shift supervisor is on site as soon as practicable.
    (4) Copies of the reports submitted every 4 weeks that summarize 
the actions taken by the owner or operator of the affected unit to 
ensure that a certified chief facility operator or certified shift 
supervisor will be on site as soon as practicable.
    (7) Records showing the names of persons who have completed a 
review of the operating manual as required by 40 CFR 60.54b(f) 
including the date of the initial review and subsequent annual reviews.
    (8) Records of steps taken to minimize emissions during startup and 
shutdown as required by paragraph (d)(5) of this section.
    (g) Reporting requirements. (1) If you are the owner or operator of 
an affected unit, you must submit the results of the performance test 
or performance evaluation of the CEMS following the procedures 
specified in Sec.  52.40(g)

[[Page 36889]]

within 60 days after the date of completing each performance test 
required by this section.
    (2) If you are the owner or operator of an affected unit, you shall 
submit an annual report in PDF format to the EPA by January 30th of 
each year via CEDRI or analogous electronic reporting approach provided 
by the EPA to report data required by this section. Annual reports 
shall be submitted following the procedures in Sec.  52.40(g). The 
report shall include all information required by paragraph (e) of this 
section, including CEMS data to demonstrate compliance with the 
applicable emissions limits under paragraph (c) of this section.

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 
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):
0
i. Removing ``2017 and each subsequent year'' and adding in its place 
``2017 through 2022''; and
0
ii. 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.

[[Page 36890]]

    (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, Sec.  52.45, or 
Sec.  52.46 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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart O--Illinois

0
8. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart P--Indiana

0
9. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart S--Kentucky

0
10. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart T--Louisiana

0
11. 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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart V--Maryland

0
12. 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

[[Page 36891]]

and for which requirements are set forth in Sec.  52.40 and Sec.  
52.41, Sec.  52.42, Sec.  52.43, Sec.  52.44, Sec.  52.45, or Sec.  
52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart X--Michigan

0
13. 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 
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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart Y--Minnesota

0
14. Amend Sec.  52.1240 by adding paragraph (d) 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.

Subpart Z--Mississippi

0
15. 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):
0
i. Removing ``2017 and each subsequent year'' and adding in its place 
``2017 through 2022''; and
0
ii. 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.

[[Page 36892]]

    (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 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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart AA--Missouri

0
16. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart DD--Nevada

0
17. 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

[[Page 36893]]

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, Sec.  52.45, or Sec.  52.46 must comply with 
such requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart FF--New Jersey

0
18. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart HH--New York

0
19. 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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart KK--Ohio

0
20. 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, Sec.  52.45, or Sec.  
52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart LL--Oklahoma

0
21. 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):
0
i. Removing ``2017 and each subsequent year'' and adding in its place 
``2017 through 2022''; and
0
ii. 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.  52.1930  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

[[Page 36894]]

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 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, Sec.  52.45, or Sec.  52.46 must 
comply with such requirements with regard to emissions occurring in 
2026 and each subsequent year.

Subpart NN--Pennsylvania

0
22. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart SS--Texas

0
23. Amend Sec.  52.2283 by:
0
a. In paragraph (d)(2):
0
i. Removing ``2017 and each subsequent year'' and adding in its place 
``2017 through 2022''; and
0
ii. 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 (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, Sec.  52.45, or Sec.  52.46 must comply with 
such requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart TT--Utah

0
24. 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

[[Page 36895]]

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, Sec.  52.45, or Sec.  52.46 must comply with 
such requirements with regard to emissions occurring in 2026 and each 
subsequent year.

Subpart VV--Virginia

0
25. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart XX--West Virginia

0
26. 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, Sec.  52.45, or 
Sec.  52.46 must comply with such requirements with regard to emissions 
occurring in 2026 and each subsequent year.

Subpart YY--Wisconsin

0
27. Amend Sec.  52.2587 by:
0
a. In paragraph (e)(2):
0
i. Removing ``2017 and each subsequent year'' and adding in its place 
``2017 through 2022''; and
0
ii. Removing the second and third sentences;
0
b. Revising paragraph (e)(3); and
0
c. Adding paragraphs (e)(4) and (5).
    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 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.

PART 75--CONTINUOUS EMISSION MONITORING

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

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

Subpart H--NOX Mass Emissions Provisions

0
29. 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

[[Page 36896]]

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
30. 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 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 heading to paragraph (f)(2); and
0
i. Revising paragraph (f)(4).
    The revisions and additions read 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 (ii). The monitoring plan also 
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 that is 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, that lists coal or a 
solid coal-derived fuel as a fuel in the unit's monitoring plan under 
Sec.  75.53 for any portion of the ozone season in the year for which 
data are being reported, that serves a generator of 100 MW or larger 
nameplate capacity, and that is not a circulating fluidized bed boiler, 
provided that through December 31, 2029, the requirements under this 
paragraph (f)(1)(x) shall apply to a unit in a given calendar year only 
if the unit also was equipped with selective catalytic reduction 
controls on or before September 30 of the previous year:
    (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;
    (E) Cumulative NOX emissions (tons, rounded to the 
nearest tenth) exceeding the applicable backstop daily NOX 
emission rate during the ozone season; and
    (F) Cumulative NOX emissions (tons, rounded to the 
nearest tenth) exceeding the applicable backstop daily NOX 
emission rate during the ozone season by more than 50 tons, calculated 
as the remainder of the amount calculated under paragraph (f)(1)(x)(E) 
of this section minus 50, but not less than zero.
    (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
31. 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
32. 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

[[Page 36897]]

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. Procedures for Heat Input

* * * * *

5.3 Heat Input Summation (for Heat Input Determined Using a Flow 
Monitor and Diluent Monitor)

* * * * *
    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] TR05JN23.003

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 to this appendix, 
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. Procedures for NOX Mass Emissions

* * * * *
    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 this appendix 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 this appendix 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 to this appendix.
[GRAPHIC] [TIFF OMITTED] TR05JN23.004

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 to this appendix:
[GRAPHIC] [TIFF OMITTED] TR05JN23.005

Where:

E(NOX)i = Apportioned NOX mass emission rate 
for the hour for unit ``i'', lb/hr.
E(NOX)CS = NOX mass emission rate for the hour 
at the common stack, lb/hr.
HIi = Heat input rate for the hour for unit ``i'','' from 
Equation F-15, F-16, F-17, F-18, F-21a, or F-21b to this appendix, 
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
33. The authority citation for part 78 continues to read as follows:

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

0
34. Amend Sec.  78.1 by:
0
a. In paragraphs (b)(13)(i), (b)(14)(i), (b)(15)(i), (b)(16)(i), and 
(b)(17)(i), removing ``decision on the'' and adding in its place 
``calculation of an'';

[[Page 36898]]

0
b. In paragraph (b)(17)(viii), adding ``or (e)'' after ``Sec.  
97.826(d)'';
0
c. In paragraph (b)(17)(ix), adding ``or (e)'' after ``Sec.  
97.811(d)'';
0
d. In paragraph (b)(18)(i), removing ``decision on the'' and adding in 
its place ``calculation of an''; and
0
e. 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 calculation of a dynamic trading budget under Sec.  
97.1010(a)(4) of this chapter.
    (ii) The calculation of an 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
35. 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
36. 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
37. 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
38. 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 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.  97.426  [Amended]

0
39. In Sec.  97.426, amend paragraph (c) by:
0
a. Removing ``set forth in'' and adding in its place ``established 
under''; and
0
b. 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
40. 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'':
0
i. Adding ``or (e)'' after ``Sec.  97.826(d)''; and
0
ii. 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
41. 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
42. 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

[[Page 36899]]

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''.

0
43. Amend Sec.  97.526 by:
0
a. In paragraph (c):
0
i. Removing ``set forth in'' and adding in its place ``established 
under''; and
0
ii. 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 ``Sec.  52.38(b)(2)(ii) of this 
chapter (or Indian'' and adding in its place ``Sec.  52.38(b)(2)(i)(B) 
of this 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)(ii)(B) 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 source 
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) 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
44. 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''; 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
45. 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
46. 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.  97.626  [Amended]

0
47. In Sec.  97.626, amend paragraph (c) by:
0
a. Removing ``set forth in'' and adding in its place ``established 
under''; and

[[Page 36900]]

0
b. Removing ``State (or Indian'' and adding in its place ``State (and 
Indian''.

Subpart DDDDD--CSAPR SO2 Group 2 Trading Program

0
48. 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''.
    The addition reads as follows:


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
49. 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
50. 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''.


Sec.  97.726  [Amended]

0
51. In Sec.  97.726, amend paragraph (c) by:
0
a. Removing ``set forth in'' and adding in its place ``established 
under''; and
0
b. Removing ``State (or Indian'' and adding in its place ``State (and 
Indian''.


Sec.  97.734  [Amended]

0
52. 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
53. 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'':
0
i. Adding ``or (e)'' after ``Sec.  97.826(d)''; and
0
ii. 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
54. Amend Sec.  97.806 by:
0
a. In paragraphs (c)(2)(i) introductory text, (c)(2)(i)(B), and 
(c)(2)(iii) and (iv),

[[Page 36901]]

removing ``base CSAPR'' and adding in its place ``CSAPR'' each time it 
appears;
0
b. In paragraph (c)(3)(i), removing ``paragraph (c)(1)'' and adding in 
its place ``paragraphs (c)(1) and (2)''; and
0
c. Removing and reserving paragraph (c)(3)(ii).


Sec.  97.810  [Amended]

0
55. 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)(20)(i) through (iii), (a)(23)(i) through 
(iii), and (b)(1), (2), (12), (13), (17), (20), and (23) by removing 
``and thereafter'' and adding in its place ``through 2022''.

0
56. 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 
(e)(1) 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 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 August 4, 2023, 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 August 21, 2023, 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

[[Page 36902]]

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 (e)(4)(ii), 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 
(e)(4)(ii) 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 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
57. 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

[[Page 36903]]

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.  97.825  [Amended]

0
58. 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
59. 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):
0
i. Removing ``set forth in'' and adding in its place ``established 
under''; and
0
ii. 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)(A)'';
0
f. 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)(A) of this chapter (and'';
0
g. Redesignating paragraph (e) as paragraph (f) and adding a new 
paragraph (e); and
0
h. Revising newly redesignated paragraphs (f)(1) and (2).
    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.
* * * * *
    (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 September 18, 2023, 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--
    (A) 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
    (B) The product of 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) and (C) of this chapter multiplied by a 
fraction whose numerator is the number of days from August 4, 2023 
through September 30, 2023, inclusive, and whose denominator is 153.
    (iii) The Administrator will allocate and record in each 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 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 September 18, 2023, 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

[[Page 36904]]

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) 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)(ii)(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 a 
control period in 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) 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)(ii)(C) 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 a 
control period in 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.

Subpart FFFFF--Texas SO2 Trading Program

0
60. 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 
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.  97.934  [Amended]

0
61. 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
62. 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. In the definition of ``Assurance account'', removing ``base CSAPR'' 
and adding in its place ``CSAPR'';
0
e. Adding in alphabetical order a definition for ``Backstop daily 
NOX emissions rate'';
0
f. Removing the definitions for ``Base CSAPR NOX Ozone 
Season Group 3 source'' and ``Base CSAPR NOX Ozone Season 
Group 3 unit'';
0
g. Adding in alphabetical order a definition for ``Coal-derived fuel'';
0
h. In the definition of ``Common designated representative'', removing 
``base CSAPR'' and adding in its place ``CSAPR'';
0
i. Revising the definition of ``Common designated representative's 
assurance level'';
0
j. In the definition of ``Common designated representative's share'', 
removing ``base CSAPR'' and adding in its place ``CSAPR'' each time it 
appears;
0
k. In the definition of ``Compliance account'', adding ``primary'' 
before ``emissions limitation'';
0
l. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 1 Trading Program'';
0
m. 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
n. In the definition of ``CSAPR NOX Ozone Season Group 3 
allowance'':
0
i. Adding ``or (e)'' after ``Sec.  97.826(d)''; and
0
ii. Adding ``or less'' after ``one ton'';
0
o. In the definitions of ``CSAPR NOX Ozone Season Group 3 
allowance deduction'' and ``CSAPR NOX Ozone Season Group 3 
emissions limitation'', adding ``primary'' before ``emissions 
limitation'';
0
p. Adding in alphabetical order a definition for ``CSAPR NOX 
Ozone Season Group 3 secondary emissions limitation'';
0
q. 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
r. Adding in alphabetical order a definition for ``CSAPR SO2 
Group 2 Trading Program'';
0
s. 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
t. In the definition of ``Excess emissions'', adding ``primary'' before 
``emissions limitation'';
0
u. Adding in alphabetical order a definition for ``Historical control 
period''; and
0
v. 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:

[[Page 36905]]

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 a NOX emissions 
rate 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).
* * * * *
    Coal-derived fuel means any fuel, whether in a solid, liquid, or 
gaseous state, produced by the mechanical, thermal, or chemical 
processing of coal.
* * * * *
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in 
a given year for which the State assurance level is exceeded as 
described in Sec.  97.1006(c)(2)(iii):
    (1) The amount (rounded to the nearest allowance) equal to the sum 
of the total amount of CSAPR NOX Ozone Season Group 3 
allowances allocated for such control period to the group of one or 
more CSAPR NOX Ozone Season Group 3 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 3 allowances purchased by an owner or operator of such 
CSAPR NOX Ozone Season Group 3 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 3 units in accordance with 
the CSAPR NOX Ozone Season Group 3 allowance auction 
provisions in a SIP revision approved by the Administrator under Sec.  
52.38(b)(11) or (12) of this chapter, multiplied by the sum 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) for 
such control period, and divided by such State NOX Ozone 
Season Group 3 trading budget;
    (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.
* * * * *
    Historical control period means, for a unit as of a given calendar 
year, the period starting May 1 of a previous calendar year and ending 
September 30 of that previous calendar year, inclusive, without regard 
to whether the unit was subject to requirements under the CSAPR 
NOX Ozone Season Group 3 Trading Program during such period.
* * * * *

0
63. Amend Sec.  97.1006 by:
0
a. Revising paragraph (b)(2), paragraph (c)(1) heading, paragraph 
(c)(1)(i), and paragraph (c)(1)(ii) introductory text;
0
b. Adding paragraphs (c)(1)(iii) and (iv);
0
c. In paragraphs (c)(2)(i) introductory text and (c)(2)(i)(B), removing 
``base CSAPR'' and adding in its place ``CSAPR'' each time it appears;
0
d. Revising paragraph (c)(2)(iii);
0
e. In paragraph (c)(2)(iv), removing ``base CSAPR'' and adding in its 
place ``CSAPR'' each time it appears;
0
f. Revising paragraph (c)(3); and
0
g. In paragraph (c)(6) introductory text, adding ``or less'' after 
``one ton''.
    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

[[Page 36906]]

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 excess, if any, over 50 tons of the sum, for all 
CSAPR NOX Ozone Season Group 3 units at the source and all 
calendar days of the control period, of any NOX emissions 
from such a unit on any calendar day of the control period exceeding 
the NOX emissions that would have occurred on that calendar 
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 
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 
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 CSAPR NOX 
Ozone Season Group 3 units at 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) and (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) August 4, 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.
    (ii) A 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
64. 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 through 2025 shall be as indicated in table 
1 to this paragraph (a)(1)(i), subject to prorating for the control 
period in 2023 as provided in paragraph (a)(1)(ii) of this section:

                       Table 1 to Paragraph (a)(1)(i)--State NOX Ozone Season Group 3 Trading Budgets by Control Period, 2021-2025
                                                                         [Tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                            Portion of
                                                                                            Portion of     2023 control
                                                                                           2023 control    period on and
                          State                                2021            2022        period before   after August        2024            2025
                                                                                             August 4,       4, 2023,
                                                                                           2023, before       before
                                                                                             prorating       prorating
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................................  ..............  ..............          13,211           6,379           6,489           6,489
Arkansas................................................  ..............  ..............           9,210           8,927           8,927           8,927
Illinois................................................          11,223           9,102           8,179           7,474           7,325           7,325
Indiana.................................................          17,004          12,582          12,553          12,440          11,413          11,413
Kentucky................................................          17,542          14,051          14,051          13,601          12,999          12,472
Louisiana...............................................          16,291          14,818          14,818           9,363           9,363           9,107
Maryland................................................           2,397           1,266           1,266           1,206           1,206           1,206
Michigan................................................          14,384          12,290           9,975          10,727          10,275          10,275
Minnesota...............................................  ..............  ..............  ..............           5,504           4,058           4,058
Mississippi.............................................  ..............  ..............           6,315           6,210           5,058           5,037
Missouri................................................  ..............  ..............          15,780          12,598          11,116          11,116
Nevada..................................................  ..............  ..............  ..............           2,368           2,589           2,545
New Jersey..............................................           1,565           1,253           1,253             773             773             773
New York................................................           4,079           3,416           3,421           3,912           3,912           3,912
Ohio....................................................          13,481           9,773           9,773           9,110           7,929           7,929
Oklahoma................................................  ..............  ..............          11,641          10,271           9,384           9,376

[[Page 36907]]

 
Pennsylvania............................................          12,071           8,373           8,373           8,138           8,138           8,138
Texas...................................................  ..............  ..............          52,301          40,134          40,134          38,542
Utah....................................................  ..............  ..............  ..............          15,755          15,917          15,917
Virginia................................................           6,331           3,897           3,980           3,143           2,756           2,756
West Virginia...........................................          15,062          12,884          12,884          13,791          11,958          11,958
Wisconsin...............................................  ..............  ..............           7,915           6,295           6,295           5,988
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (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, rounded to the nearest allowance, of the following prorated 
amounts:
    (A) The product of the non-prorated trading budget for the portion 
of the 2023 control period before August 4, 2023, shown for the State 
in table 1 to paragraph (a)(1)(i) of this section (or zero if table 1 
to paragraph (a)(1)(i) 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 August 
4, 2023, inclusive, and whose denominator is 153; plus
    (B) The product of the non-prorated trading budget for the portion 
of the 2023 control period on and after August 4, 2023, 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 August 4, 2023, 
through September 30, 2023, inclusive, and whose denominator is 153.
    (2)(i) The State NOX Ozone Season Group 3 trading budget 
for each State and each control period in 2026 through 2029 shall be 
the preset trading budget indicated for the State and control period in 
table 2 to this paragraph (a)(2)(i), except as provided in paragraph 
(a)(2)(ii) of this section.

               Table 2 to Paragraph (a)(2)(i)--Preset Trading Budgets by Control Period, 2026-2029
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                      State                            2026            2027            2028            2029
----------------------------------------------------------------------------------------------------------------
Alabama.........................................           6,339           6,236           6,236           5,105
Arkansas........................................           6,365           4,031           4,031           3,582
Illinois........................................           5,889           5,363           4,555           4,050
Indiana.........................................           8,363           8,135           7,280           5,808
Kentucky........................................           9,697           7,908           7,837           7,392
Louisiana.......................................           6,370           3,792           3,792           3,639
Maryland........................................             842             842             842             842
Michigan........................................           6,743           5,691           5,691           4,656
Minnesota.......................................           4,058           2,905           2,905           2,578
Mississippi.....................................           3,484           2,084           1,752           1,752
Missouri........................................           9,248           7,329           7,329           7,329
Nevada..........................................           1,142           1,113           1,113             880
New Jersey......................................             773             773             773             773
New York........................................           3,650           3,388           3,388           3,388
Ohio............................................           7,929           7,929           6,911           6,409
Oklahoma........................................           6,631           3,917           3,917           3,917
Pennsylvania....................................           7,512           7,158           7,158           4,828
Texas...........................................          31,123          23,009          21,623          20,635
Utah............................................           6,258           2,593           2,593           2,593
Virginia........................................           2,565           2,373           2,373           1,951
West Virginia...................................          10,818           9,678           9,678           9,678
Wisconsin.......................................           4,990           3,416           3,416           3,416
----------------------------------------------------------------------------------------------------------------

    (ii) If the preset trading budget indicated for a given State and 
control period in table 2 to paragraph (a)(2)(i) of this section is 
less than the dynamic trading budget for the State and control period 
referenced in the applicable notice promulgated under paragraph 
(a)(4)(v)(C) of this section, then the State NOX Ozone 
Season Group 3 trading budget for the State and control period shall be 
the dynamic trading budget for the State and control period referenced 
in the applicable notice promulgated under paragraph (a)(4)(v)(C) of 
this section.
    (3) The State NOX Ozone Season Group 3 trading budget 
for each State and each control period in 2030 and thereafter shall be 
the dynamic trading budget for the State and control period referenced 
in the applicable notice promulgated under paragraph (a)(4)(v)(C) of 
this section.
    (4) The Administrator will calculate the dynamic trading budget for 
each State and each control period in 2026

[[Page 36908]]

and thereafter in the year before the year of the control period as 
follows:
    (i) The Administrator will include a unit in a State (and Indian 
country within the borders of the State) in the calculation of the 
State's dynamic trading budget for a control period if--
    (A) To the best of the Administrator's knowledge, the unit 
qualifies as a CSAPR NOX Ozone Season Group 3 unit under 
Sec.  97.1004, without regard to whether the unit has permanently 
retired, provided that including a unit in the calculation of a dynamic 
trading budget does not constitute a determination that the unit is a 
CSAPR NOX Ozone Season Group 3 unit, and not including a 
unit in the calculation of a dynamic trading budget does not constitute 
a determination that the unit is not a CSAPR NOX Ozone 
Season Group 3 unit;
    (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 for which the dynamic trading 
budget is being calculated; and
    (C) The owner or operator reported heat input greater than zero for 
the unit in accordance with part 75 of this chapter for the historical 
control period in the year two years before the year of the control 
period for which the dynamic trading budget is being calculated.
    (ii) For each unit identified for inclusion in the calculation of 
the State's dynamic trading budget for a control period under paragraph 
(a)(4)(i) of this section, the Administrator will calculate the heat 
input amount in mmBtu to be used in the budget calculation as follows:
    (A) For each such unit, the Administrator will determine the 
following unit-level amounts:
    (1) The total heat input amounts reported in accordance with part 
75 of this chapter for the unit for the historical control periods in 
the years two, three, four, five, and six years before the year of the 
control period for which the dynamic trading budget is being 
calculated, except any historical control period that commenced before 
the unit's first deadline under any regulatory program to begin 
recording and reporting heat input in accordance with part 75 of this 
chapter; and
    (2) The average of the three highest unit-level total heat input 
amounts identified for the unit under paragraph (a)(4)(iv)(A)(1) of 
this section or, if fewer than three non-zero amounts are identified 
for the unit, the average of all such non-zero total heat input 
amounts.
    (B) For the State, the Administrator will determine the following 
state-level amounts:
    (1) The sum for all units in the State meeting the criterion under 
paragraph (a)(4)(i)(A) of this section, without regard to whether such 
units also meet the criteria under paragraphs (a)(4)(i)(B) and (C) of 
this section, of the total heat input amounts reported in accordance 
with part 75 of this chapter for the historical control periods in the 
years two, three, and four years before the year of the control period 
for which the dynamic trading budget is being calculated, provided that 
for the historical control periods in 2022 and 2023, the total reported 
heat input amounts for Nevada and Utah as otherwise determined under 
this paragraph (a)(4)(ii)(B)(1) shall be increased by 13,489,332 mmBtu 
for Nevada and by 1,888,174 mmBtu for Utah;
    (2) The average of the three state-level total heat input amounts 
calculated for the State under paragraph (a)(4)(ii)(B)(1) of this 
section; and
    (3) The sum for all units identified for inclusion in the 
calculation of the State's dynamic trading budget for the control 
period under paragraph (a)(4)(i) of this section of the unit-level 
average heat input amounts calculated under paragraph (a)(4)(ii)(A)(2) 
of this section.
    (C) The heat input amount for a unit used in the calculation of the 
State's dynamic trading budget shall be the product of the unit-level 
average total heat input amount calculated for the unit under paragraph 
(a)(4)(ii)(A)(2) of this section multiplied by a fraction whose 
numerator is the state-level average total heat input amount calculated 
under paragraph (a)(4)(ii)(B)(2) of this section and whose denominator 
is the state-level sum of the unit-level average heat input amounts 
calculated under paragraph (a)(4)(ii)(B)(3) of this section.
    (iii) For each unit identified for inclusion in the calculation of 
the State's dynamic trading budget for a control period under paragraph 
(a)(4)(i) of this section, the Administrator will identify the 
NOX emissions rate in lb/mmBtu to be used in the calculation 
as follows:
    (A) For a unit listed in the document entitled ``Unit-Specific 
Ozone Season NOX Emissions Rates for Dynamic Budget 
Calculations'' posted at www.regulations.gov in docket EPA-HQ-OAR-2021-
0668, 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 that document.
    (B) For a unit not listed in the document referenced in paragraph 
(a)(4)(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) 0.011 lb/mmBtu, for a simple cycle combustion turbine or a 
combined cycle combustion turbine other than an integrated coal 
gasification combined cycle unit;
    (2) 0.030 lb/mmBtu, for 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)(4)(iii)(B)(1) or (2) of this section.
    (iv) The Administrator will calculate the State's dynamic trading 
budget for the control period 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)(4)(i) of this section, of the product for each such unit of the 
heat input amount in mmBtu calculated for the unit under paragraph 
(a)(4)(ii) of this section multiplied by the NOX emissions 
rate in lb/mmBtu identified for the unit under paragraph (a)(4)(iii) of 
this section.
    (v)(A) By March 1, 2025 and March 1 of each year thereafter, the 
Administrator will calculate the dynamic trading budget for each State, 
in accordance with paragraphs (a)(4)(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 (a)(4)(v)(A) 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)(4)(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)(4)(v)(A) of this section.
    (C) The Administrator will adjust the calculations to the extent 
necessary to

[[Page 36909]]

ensure that they are in accordance with the provisions referenced in 
paragraph (a)(4)(v)(A) of this section. By May 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(a)(4)(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)(4)(v)(B) of this section.
    (b) 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).
    (c) New unit set-asides. (1) The new unit set-asides for 
allocations of CSAPR NOX Ozone Season Group 3 allowances for 
the control periods in 2021 and 2022 for each State with CSAPR 
NOX Ozone Season Group 3 trading budgets for such control 
periods shall be as indicated in table 3 to this paragraph (c)(1):

   Table 3 to Paragraph (c)(1)--New Unit Set-Asides by Control Period
                           [2021-2022 (tons)]
------------------------------------------------------------------------
                          State                            2021    2022
------------------------------------------------------------------------
Illinois................................................     265     265
Indiana.................................................     262     254
Kentucky................................................     309     283
Louisiana...............................................     430     430
Maryland................................................     135     115
Michigan................................................     500     482
New Jersey..............................................      27      27
New York................................................     168     168
Ohio....................................................     291     290
Pennsylvania............................................     335     339
Virginia................................................     185     161
West Virginia...........................................     266     261
------------------------------------------------------------------------

    (2) The new 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 product (rounded to 
the nearest allowance) of the State NOX Ozone Season Group 3 
trading budget for the State and control period established in 
accordance with paragraph (a) of this section multiplied by--
    (i) 0.09, for Nevada for the control periods in 2023 through 2025;
    (ii) 0.06, for Ohio for the control periods in 2023 through 2025;
    (iii) 0.05, for each State other than Nevada and Ohio for the 
control periods in 2023 through 2025; or
    (iv) 0.05, for each State for each control period in 2026 and 
thereafter.
    (d) Indian country new unit set-asides for the control periods in 
2021 and 2022. The Indian country new unit set-asides for allocations 
of CSAPR NOX Ozone Season Group 3 allowances for the control 
periods in 2021 and 2022 for each State with CSAPR NOX Ozone 
Season Group 3 trading budgets for such control periods shall be as 
indicated in table 4 to this paragraph (d):

 Table 4 to Paragraph (d)--Indian Country New Unit Set-Asides by Control
                                 Period
                           [2021-2022 (tons)]
------------------------------------------------------------------------
                          State                            2021    2022
------------------------------------------------------------------------
Illinois................................................  ......  ......
Indiana.................................................  ......  ......
Kentucky................................................  ......  ......
Louisiana...............................................      15      15
Maryland................................................  ......  ......
Michigan................................................      13      12
New Jersey..............................................  ......  ......
New York................................................       3       3
Ohio....................................................  ......  ......
Pennsylvania............................................  ......  ......
Virginia................................................  ......  ......
West Virginia...........................................  ......  ......
------------------------------------------------------------------------

    (e) Variability limits. (1) The variability limits for the State 
NOX Ozone Season Group 3 trading budgets for the control 
periods in 2021 and 2022 for each State with such trading budgets for 
such control periods shall be as indicated in table 5 to this paragraph 
(e)(1).

    Table 5 to Paragraph (e)(1)--Variability Limits by Control Period
                           [2021-2022 (tons)]
------------------------------------------------------------------------
                          State                            2021    2022
------------------------------------------------------------------------
Illinois................................................   2,356   1,911
Indiana.................................................   3,571   2,642
Kentucky................................................   3,684   2,951
Louisiana...............................................   3,421   3,112
Maryland................................................     504     266
Michigan................................................   3,021   2,581
New Jersey..............................................     329     263
New York................................................     856     717
Ohio....................................................   2,831   2,052
Pennsylvania............................................   2,535   1,758
Virginia................................................   1,329     818
West Virginia...........................................   3,163   2,706
------------------------------------------------------------------------

    (2) The variability limit for the State NOX Ozone Season 
Group 3 trading budget for each State for each control period in 2023 
and thereafter shall be calculated as the product (rounded to the 
nearest ton) of the State NOX Ozone Season Group 3 trading 
budget for the State and control period established in accordance with 
paragraph (a) 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--
    (A) The sum for all CSAPR NOX Ozone Season Group 3 units 
in the State and Indian country within the borders of the State of the 
total heat input reported for the control period in mmBtu, provided 
that, for purposes of this paragraph (e)(2)(ii)(A), the 2023 control 
period for all States shall be deemed to be the period from May 1, 2023 
through September 30, 2023, inclusive; divided by
    (B) The state-level total heat input amount used in the calculation 
of the State NOX Ozone Season Group 3 trading budget for the 
State and control period in mmBtu, as identified in accordance with 
paragraph (e)(3) of this section.
    (3) For purposes of paragraph (e)(2)(ii)(B) of this section, the 
state-level total heat input amount used in the calculation of a State 
NOX Ozone Season Group 3 trading budget for a given control 
period shall be identified as follows:
    (i) For a control period in 2023 through 2025, and for a control 
period in 2026 through 2029 if the State NOX Ozone Season 
Group 3 trading budget for the State and control period under paragraph 
(a)(2) of this section is the preset trading budget set forth for the 
State and control period in table 2 to paragraph (a)(2)(i) of this 
section, the state-level total heat input amounts shall be as indicated 
in table 6 to this paragraph (e)(3)(i).

[[Page 36910]]



              Table 6 to Paragraph (e)(3)(i)--State-Level Total Heat Input Used in Calculations of Preset Trading Budgets by Control Period
                                                                   [2023-2029 (mmBtu)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                  State                        2023            2024            2025            2026            2027            2028            2029
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................     313,037,541     333,030,691     333,030,691     330,396,046     328,650,653     328,650,653     307,987,882
Arkansas................................     192,843,561     192,843,561     192,843,561     190,921,052     190,921,052     190,921,052     190,921,052
Illinois................................     274,005,935     286,568,112     286,568,112     253,219,463     253,219,463     214,086,655     193,900,867
Indiana.................................     356,047,916     330,175,944     330,175,944     302,245,332     302,245,332     277,218,546     236,611,101
Kentucky................................     301,161,750     301,161,750     295,857,697     295,857,697     295,857,697     293,016,485     274,595,978
Louisiana...............................     280,592,592     280,592,592     278,766,253     278,461,807     277,262,840     277,262,840     277,262,840
Maryland................................      70,725,007      70,725,007      70,725,007      70,725,007      70,725,007      70,725,007      70,725,007
Michigan................................     313,846,533     299,124,688     299,124,688     258,225,107     258,225,107     258,225,107     222,314,181
Minnesota...............................     128,893,685     107,821,236     107,821,236     107,821,236      93,890,928      93,890,928      85,707,385
Mississippi.............................     192,978,295     189,415,018     189,279,160     189,279,160     189,279,160     176,004,820     176,004,820
Missouri................................     284,308,851     249,153,661     249,153,661     249,153,661     248,413,545     248,413,545     248,413,545
Nevada..................................     103,489,785     116,979,117     114,729,782     105,018,415     100,193,805     100,193,805      96,378,269
New Jersey..............................     112,233,231     112,233,231     112,233,231     112,233,231     112,233,231     112,233,231     112,233,231
New York................................     242,853,661     242,853,661     242,853,661     242,853,661     242,853,661     242,853,661     242,853,661
Ohio....................................     412,292,609     386,560,212     386,560,212     386,560,212     386,560,212     358,992,155     342,075,946
Oklahoma................................     212,903,386     211,187,283     211,165,691     211,145,820     196,160,642     196,160,642     196,160,642
Pennsylvania............................     550,993,363     550,993,363     550,993,363     550,993,363     550,993,363     550,993,363     487,590,728
Texas...................................   1,395,116,925   1,395,116,925   1,389,251,813   1,389,251,813   1,356,192,532   1,320,040,162   1,280,014,875
Utah....................................     164,519,648     166,407,822     166,407,822     127,217,396     127,217,396     127,217,396     127,217,396
Virginia................................     202,953,791     194,015,719     194,015,719     194,015,719     194,015,719     194,015,719     186,848,587
West Virginia...........................     306,845,495     273,151,957     273,151,957     273,151,957     273,151,957     273,151,957     273,151,957
Wisconsin...............................     220,794,282     220,792,155     213,038,308     185,469,476     151,343,287     151,343,287     151,343,287
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (ii) For a control period in 2026 through 2029 if the State 
NOX Ozone Season Group 3 trading budget for the State and 
control period under paragraph (a)(2) of this section is the dynamic 
trading budget for the State and control period referenced in the 
applicable notice promulgated under paragraph (a)(4)(v)(C) of this 
section, and for a control period in 2030 and thereafter, the state-
level total heat input amount shall be the amount for the State and 
control period calculated under paragraph (a)(4)(ii)(B)(2) 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 an Indian country existing unit 
set-aside, a new unit set-aside, or an Indian country new unit set-
aside but does not include any tons in a variability limit.

0
65. Amend Sec.  97.1011 by revising the section heading and paragraphs 
(a), (b), paragraph (c) heading, and paragraphs (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 2026, 
the notices of data availability will be the notices issued under 
paragraph (b)(11)(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 2026, the notices of data availability will be the notices 
issued under paragraph (b)(11)(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 2026 and thereafter. For each control period in 2026 
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 the 
Administrator will calculate default allocations shall be the remainder 
of the State NOX Ozone Season Group 3 trading budget for the 
control period under Sec.  97.1010(a) minus the new unit set-aside for 
the control period under Sec.  97.1010(c).
    (2) The Administrator will calculate a default allocation of CSAPR 
NOX Ozone Season Group 3 allowances for each CSAPR 
NOX Ozone Season Group 3 unit in the State and Indian 
country within the borders of the State meeting the following criteria:
    (i) To the best of the Administrator's knowledge, the unit 
qualifies as a CSAPR NOX Ozone Season Group 3 unit under 
Sec.  97.1004, without regard to whether the unit has permanently 
retired;
    (ii) 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 for which the allowances are 
being allocated; and
    (iii) The owner or operator reported heat input greater than zero 
for the unit in accordance with part 75 of this chapter for the 
historical control period in the year two years before the year of the 
control period for which the allowances are being allocated.
    (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 calculate an average heat input amount to be 
used in the allocation calculations as follows:
    (i) The Administrator will identify the total heat input amounts 
reported for the unit in accordance with part 75 of this chapter for 
the historical control periods in the years two, three, four, five, and 
six years before the year of the control period for which the 
allowances are being allocated, except any

[[Page 36911]]

historical control period that commenced before the unit's first 
deadline under any regulatory program to begin recording and reporting 
heat input in accordance with part 75 of this chapter.
    (ii) The average heat input amount used in the allocation 
calculations shall be the average of the three highest total heat input 
amounts identified for the unit under paragraph (b)(3)(i) of this 
section or, if fewer than three non-zero amounts are identified for the 
unit, the average of all such non-zero total heat input amounts.
    (4) For each CSAPR NOX Ozone Season Group 3 unit for 
which a default allocation is being calculated for a control period, 
the Administrator will calculate a tentative maximum allocation amount 
to be used in the allocation calculations as follows:
    (i) The Administrator will identify the total NOX 
emissions amounts reported for the unit in accordance with part 75 of 
this chapter for the historical control periods in the years two, 
three, four, five, and six years before the year of the control period 
for which the allowances are being allocated.
    (ii) The tentative maximum allocation amount used in the allocation 
calculations shall be the highest of the total NOX emissions 
amounts identified for the unit under paragraph (b)(4)(i) of this 
section or, if less, any applicable amount calculated under paragraph 
(b)(4)(iii) of this section.
    (iii)(A) The tentative maximum allocation amount under paragraph 
(b)(4)(ii) of this section for a unit described in paragraph 
(b)(4)(iii)(B) or (C) of this section may not exceed a maximum 
controlled baseline calculated as the product (converted to tons at a 
conversion factor of 2,000 lb/ton and rounded to the nearest ton) of 
the highest total heat input amount identified for the unit under 
paragraph (b)(3)(i) of this section in mmBtu multiplied by a 
NOX emissions rate of 0.08 lb/mmBtu.
    (B) For the control period in 2026, a maximum controlled baseline 
under paragraph (b)(4)(iii)(A) of this section shall apply to any unit 
that combusted any coal or solid coal-derived fuel during the 
historical control period for which the unit's heat input was most 
recently reported, that serves a generator with nameplate capacity of 
100 MW or more, and that is equipped with selective catalytic reduction 
controls, except a circulating fluidized bed boiler.
    (C) For each control period in 2027 and thereafter, a maximum 
controlled baseline under paragraph (b)(4)(iii)(A) of this section 
shall apply to any unit that combusted any coal or solid coal-derived 
fuel during the historical control period for which the unit's heat 
input was most recently reported and that serves a generator with 
nameplate capacity of 100 MW or more, except a circulating fluidized 
bed boiler.
    (5) 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)(6) of this section and will 
recalculate the unrounded default allocations according to the 
procedures in paragraph (b)(7) or (8) 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.
    (6) 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 default allocations, of the units' average heat input amounts 
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 amount determined under paragraph (b)(3)(ii) of this section and 
whose denominator is the sum determined under paragraph (b)(6)(i) of 
this section; and
    (B) The unit's tentative maximum allocation amount determined under 
paragraph (b)(4)(ii) of this section.
    (iii) If the sum of the unrounded default allocations determined 
under paragraph (b)(6)(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)(7) or (8) of this section, as applicable.
    (iv) If the sum of the unrounded default allocations determined 
under paragraph (b)(6)(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)(9) 
and (10) of this section.
    (7) 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 
tentative maximum allocation amount determined under paragraph 
(b)(4)(ii) 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 default allocations.
    (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' tentative 
maximum allocation amounts determined under paragraph (b)(4)(ii) of 
this section, of the units' average heat input amounts 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 procedure was less than the 
unit's tentative maximum allocation amount determined under paragraph 
(b)(4)(ii) of this section, the Administrator will recalculate the 
unit's unrounded default allocation 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)(7)(i) 
of this section multiplied by a fraction whose numerator is the unit's 
average heat input amount determined under paragraph (b)(3)(ii) of this 
section and whose denominator is the sum determined under paragraph 
(b)(7)(ii) of this section; and
    (B) The unit's tentative maximum allocation amount determined under 
paragraph (b)(4)(ii) of this section.
    (iv) Except as provided in paragraph (b)(7)(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)(7)(iii) and (iv) of this section is less than the 
total amount of

[[Page 36912]]

allowances determined for the State and control period under paragraph 
(b)(1) of this section, the Administrator will iterate the procedures 
in paragraph (b)(7) of this section or follow the procedures in 
paragraph (b)(8) of this section, as applicable.
    (vi) If the sum of the unrounded default allocations determined 
under paragraphs (b)(7)(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)(9) and (10) of this section.
    (8) 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 tentative maximum allocation 
amount determined under paragraph (b)(4)(ii) 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 default allocations.
    (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)(8)(i) of this section multiplied by a fraction 
whose numerator is the unit's average heat input amount determined 
under paragraph (b)(3)(ii) of this section and whose denominator is the 
sum determined under paragraph (b)(6)(i) of this section.
    (9) The Administrator will round the default allocation for each 
eligible unit determined under paragraph (b)(6), (7), or (8) of this 
section to the nearest allowance and make any adjustments required 
under paragraph (b)(10) of this section.
    (10) If the sum of the default allocations after rounding under 
paragraph (b)(9) of this section does not equal the total amount of 
allowances determined for the State and control period under paragraph 
(b)(1) of this 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)(9) 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.
    (11)(i) By March 1, 2025 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 (10) 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 (b)(11)(i) 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)(11)(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)(11)(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)(11)(i) of this section. By May 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(11)(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)(11)(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 CSAPR NOX Ozone Season Group 3 allowances were 
allocated to the recipient for such control period 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.
* * * * *
    (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

[[Page 36913]]

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
66. 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 paragraph (a)(4)(i);
0
h. Redesignating paragraph (a)(4)(ii) as paragraph (a)(4)(iii) and 
adding a new paragraph (a)(4)(ii);
0
i. Revising paragraphs (a)(5) and (10):
0
j. 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
k. Adding paragraph (a)(13);
0
l. Revising paragraphs (b) introductory text and (b)(1) and (2);
0
m. 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
n. Revising paragraph (b)(10);
0
o. 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
p. 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 
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(c) 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.
    (4)(i) The allocation to each CSAPR NOX Ozone Season 
Group 3 unit described in paragraphs (a)(1)(i) through (iii) of this 
section and for each control period described in paragraph (a)(3) of 
this section will be an amount equal to the unit's total tons of 
NOX emissions during the control period or, if less, any 
applicable amount calculated under paragraph (a)(4)(ii) of this 
section.
    (ii)(A) The allocation under paragraph (a)(4)(i) of this section to 
a unit described in paragraph (a)(4)(ii)(B) or (C) of this section may 
not exceed a maximum controlled baseline calculated as the product 
(converted to tons at a conversion factor of 2,000 lb/ton and rounded 
to the nearest ton) of the unit's total heat input during the control 
period in mmBtu multiplied by a NOX emissions rate of 0.08 
lb/mmBtu.
    (B) For a control period in 2024 through 2026, a maximum controlled 
baseline under paragraph (a)(4)(ii)(A) of this section shall apply to 
any unit combusting any coal or solid coal-derived fuel during the 
control period, serving a generator with nameplate capacity of 100 MW 
or more, and equipped with selective catalytic reduction controls on or 
before September 30 of the preceding control period, except a 
circulating fluidized bed boiler.
    (C) For a control period in 2027 and thereafter, a maximum 
controlled baseline under paragraph (a)(4)(ii)(A) of this section shall 
apply to any unit combusting any coal or solid coal-derived fuel during 
the control period and serving a generator with nameplate capacity of 
100 MW or more, except a circulating fluidized bed boiler.
* * * * *
    (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

[[Page 36914]]

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 (a)(13)(i) 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 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 referenced in 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(d) 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 
(b)(13)(i) 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

[[Page 36915]]

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
67. 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. Adding paragraphs (d) and (e);
0
e. In paragraph (f), removing ``Sec.  97.1011(a), or'' and adding in 
its place ``Sec.  97.1011(a)(1), or'';
0
f. Redesignating paragraphs (g) and (h) as paragraphs (i) and (j), 
respectively, and adding new paragraphs (g) and (h);
0
g. Revising newly redesignated paragraph (i);
0
h. In newly redesignated paragraph (j), removing ``and May 1 of each 
year thereafter, the'' and adding in its place ``, and May 1, 2023, 
the''; 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 September 5, 2023, 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 September 5, 2023, 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 August 4, 2023, 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

[[Page 36916]]

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.
* * * * *
    (g) By September 5, 2023, 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.
    (h) 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 (h).
    (i) 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).
* * * * *

0
68. 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; backstop daily NOX emissions rate.

* * * * *
    (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 excess, if any, over 50 tons of the sum 
(converted to tons at a conversion factor of 2,000 lb/ton and rounded 
to the nearest ton), for all calendar days in the control period and 
all CSAPR NOX Ozone Season Group 3 units at the source to 
which the backstop daily NOX emissions rate applies for the 
control period under paragraph (b)(3) of this section, of any amount by 
which a unit's NOX emissions for a given calendar day in 
pounds exceed the product in pounds of the unit's total heat input in 
mmBtu for that calendar day multiplied by 0.14 lb/mmBtu; or
* * * * *
    (3) The backstop daily NOX emissions rate of 0.14 lb/
mmBtu applies as follows:
    (i) For each control period in 2024 through 2029, the backstop 
daily NOX emissions rate shall apply to each CSAPR 
NOX Ozone Season Group 3 unit combusting any coal or solid 
coal-derived fuel during the control period, serving a generator with 
nameplate capacity of 100 MW or more, and equipped with selective 
catalytic reduction controls on or before September 30 of the preceding 
control period, except a circulating fluidized bed boiler.
    (ii) For each control in 2030 and thereafter, the backstop daily 
NOX emissions rate shall apply to each CSAPR NOX 
Ozone Season Group 3 unit combusting any coal or solid coal-derived 
fuel during the control period and serving a generator with nameplate 
capacity of 100 MW or more, except a circulating fluidized bed boiler.
* * * * *

0
69. Amend Sec.  97.1025 by:
0
a. Revising the section heading;
0
b. In 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), removing 
``base CSAPR'' and adding in its place ``CSAPR'' each time it appears; 
and
0
c. Adding paragraph (c).
    The revision and addition 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 CSAPR NOX Ozone Season Group 
3 unit equipped with selective catalytic reduction controls or 
selective non-catalytic reduction controls 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 (c)(1) shall 
apply to a unit for a control period only if:
    (i) The unit is included for the control period in a group of CSAPR 
NOX Ozone Season Group 3 units at 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 historical 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 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 historical 
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 historical control period shall be calculated from such reported 
data as the quotient (converted to lb/mmBtu at a conversion factor of 
2,000 lb/ton, and rounded to the nearest 0.0001 lb/mmBtu) of the unit's 
total NOX emissions in tons for the historical control 
period divided by the unit's total heat input in mmBtu for the 
historical control period.

0
70. Amend Sec.  97.1026 by:

[[Page 36917]]

0
a. Revising the section heading and paragraph (b);
0
b. In paragraph (c):
0
i. Removing ``set forth in'' and adding in its place ``established 
under''; and
0
ii. 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; bank recalibration.

* * * * *
    (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 and thereafter, 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 year thereafter, 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 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.
    (ii) 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 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 multiplied by--
    (A) 0.210, for a control period in 2024 through 2029; or
    (B) 0.105, for a control period in 2030 and thereafter.
    (3) If the total amount of CSAPR NOX Ozone Season Group 
3 allowances determined under paragraph (d)(2)(i) of this section 
exceeds the CSAPR NOX Ozone Season Group 3 allowance bank 
ceiling target 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)(ii) 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)(i) 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).
    (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
71. 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)'' each time it appears.
    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) August 4, 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, 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) January 31, 2024, 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

[[Page 36918]]

part 75 to address other regulatory requirements.
* * * * *

0
72. 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 August 4, 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)(C) of this chapter;
* * * * *
[FR Doc. 2023-05744 Filed 6-2-23; 8:45 am]
 BILLING CODE 6560-50-P


