20036 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 52, 75, 78 and 97 

[EPA–HQ–OAR–2021–0668; FRL 8670–01– 

OAR] 

RIN 2060–AV51 

Federal Implementation Plan 

Addressing Regional Ozone Transport 

for the 2015 Ozone National Ambient 

Air Quality Standard 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: This action proposes Federal 

Implementation Plan (FIP) requirements 

to address twenty-six states’ obligations 

to eliminate significant contribution to 

nonattainment, or interference with 

maintenance, of the 2015 ozone 

National Ambient Air Quality Standard 

(NAAQS) in other states. The U.S. 

Environmental Protection Agency (EPA) 

is proposing this action under the ‘‘good 

neighbor’’ or ‘‘interstate transport’’ 

provision of the Clean Air Act (CAA or 

Act). The Agency proposes establishing 

nitrogen oxides emissions budgets 

requiring fossil fuel-fired power plants 

in 25 states to participate in an 

allowance-based ozone season trading 

program beginning in 2023. The Agency 

is also proposing to establish nitrogen 

oxides emissions limitations applicable 

to certain other industrial stationary 

sources in 23 states with an earliest 

possible compliance date of 2026. These 

industrial source types are: 

Reciprocating internal combustion 

engines in Pipeline Transportation of 

Natural Gas; kilns in Cement and 

Cement Product Manufacturing; boilers 

and furnaces in Iron and Steel Mills and 

Ferroalloy Manufacturing; furnaces in 

Glass and Glass Product Manufacturing; 

and high-emitting equipment and large 

boilers in Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. 

DATES: Comments must be received on 

or before June 6, 2022. 

Public Hearing: The EPA will hold a 

virtual public hearing on April 21, 2022. 

Please refer to the SUPPLEMENTARY

INFORMATION section for additional 

information on the public hearing. 

Information Collection Request (ICR): 

Under the Paperwork Reduction Act 

(PRA), comments on the information 

collection provisions are best assured of 

consideration if the Office of 

Management and Budget (OMB) 

receives a copy of your comments on or 

before May 6, 2022. 

ADDRESSES: You may send comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2021–0668; via the Federal 

eRulemaking Portal: https://

www.regulations.gov/ (our preferred 

method). Follow the online instructions 

for submitting comments. 

Instructions: All submissions received 

must include the Docket ID No. for this 

rulemaking. Comments received may be 

posted without change to https://

www.regulations.gov/, including any 

personal information provided. For 

detailed instructions on sending 

comments and additional information 

on the rulemaking process, see the 

‘‘Public Participation’’ heading of the 

SUPPLEMENTARY INFORMATION section of 

this document. Out of an abundance of 

caution for members of the public and 

our staff, the EPA Docket Center and 

Reading Room are open to the public by 

appointment only to reduce the risk of 

transmitting COVID–19. Our Docket 

Center staff also continues to provide 

remote customer service via email, 

phone, and webform. Hand deliveries 

and couriers may be received by 

scheduled appointment only. For 

further information on EPA Docket 

Center services and the current status, 

please visit us online at https://

www.epa.gov/dockets. 

The virtual public hearing will be 

held on April 21, 2022. The virtual 

public hearing will convene at 10 a.m. 

Eastern Time (ET) and will conclude at 

7 p.m. ET. The EPA may close a session 

15 minutes after the last pre-registered 

speaker has testified if there are no 

additional speakers. For information or 

questions about the public hearing, 

please contact Ms. Holly DeJong at 

Dejong.holly@epa.gov. The EPA will 

announce further details at https://

www.epa.gov/csapr/csapr-2015-ozonenaaqs. Refer to the SUPPLEMENTARY

INFORMATION section for additional 

information. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Elizabeth Selbst, Air Quality Policy 

Division, Office of Air Quality Planning 

and Standards (C539–01), 

Environmental Protection Agency, 109 

TW Alexander Drive, Research Triangle 

Park, NC 27711; telephone number: 

(919)-541–3918; email address: 

Selbst.elizabeth@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Preamble Glossary of Terms and 

Abbreviations 

The following are abbreviations of 

terms used in the preamble. 

2016v1 2016 Version 1 Emissions Modeling 

Platform 

2016v2 2016 Version 2 Emissions Modeling 

Platform 

4-Step Framework 4-Step Interstate 

Transport Framework 

ACS American Community Survey 

AEO Annual Energy Outlook 

AQAT Air Quality Assessment Tool 

AQMTSD Air Quality Modeling Technical 

Support Document 

BACT Best Available Control Technology 

BPT Benefit Per Ton 

CAA or Act Clean Air Act 

CAIR Clean Air Interstate Rule 

CBI Confidential Business Information 

CCR Coal Combustion Residual 

CDC Centers for Disease Control and 

Prevention 

CEMS Continuous Emissions Monitoring 

Systems 

CES Clean Energy Standards 

CHP Combined Heat and Power 

CMDB Control Measures Database 

CMV Commercial Marine Vehicle 

CoST Control Strategy Tool 

CPT Cost Per Ton 

CSAPR Cross-State Air Pollution Rule 

EGU Electric Generating Unit 

EIA U.S. Energy Information Agency 

EISA Energy Independence and Security 

Act 

ELG Effluent Limitation Guidelines 

E.O. Executive Order 

EPA or the Agency United States 

Environmental Protection Agency 

FFS Finding of Failure To Submit 

FIP Federal Implementation Plan 

GIS Geographic Information System 

HDGHG Greenhouse Gas Emissions and 

Fuel Efficiency Standards for Medium- and 

Heavy-Duty Engines and Vehicles 

HEDD High Electricity Demand Days 

ICI Industrial, Commercial, and 

Institutional 

I/M Inspection and Maintenance 

IPM Integrated Planning Model 

LNB Low-NOX Burners 

MJO Multi-Jurisdictional Organization 

MOVES Motor Vehicle Emission Simulator 

MSAT2 Mobile Source Air Toxics Rule 

MWC Municipal Waste Combustor 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System 

NEEDS National Electric Energy Data 

System 

NEI National Emissions Inventory 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

No SISNOSE No Significant Economic 

Impact on a Substantial Number of Small 

Entities 

Non-EGU Non-Electric Generating Unit 

NOX Nitrogen Oxides 

NSPS New Source Performance Standard 

NREL National Renewable Energy Lab 

NTTAA National Technology Transfer and 

Advancement Act 

OFA Over-Fire Air 

OMB United States Office of Management 

and Budget 

OSAT/APCA Ozone Source Apportionment 

Technology/Anthropogenic Precursor 

Culpability Analysis 

OTC Ozone Transport Commission 

OTR Ozone Transport Region 

OTSA Oklahoma Tribal Statistical Area 

PEMS Predictive Emissions Monitoring 

Systems 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20037 

PM2.5 Fine Particulate Matter 

ppb parts per billion 

ppm parts per million 

ppmvd parts per million by volume, dry 

PRA Paperwork Reduction Act 

RACT Reasonably Available Control 

Technology 

RFA Regulatory Flexibility Act 

RICE Reciprocating Internal Combustion 

Engines 

ROP Rate of Progress 

RPS Renewable Portfolio Standards 

RRF Relative Response Factor 

SAFE Safer Affordable Fuel-Efficient 

Vehicles Rule 

SAFETEA Safe, Accountable, Flexible, 

Efficient, Transportation Equity Act 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

SMOKE Sparse Matrix Operator Kernel 

Emissions 

SNCR Selective Non-Catalytic Reduction 

SO2 Sulfur Dioxide 

tpd ton per day 

TSD Technical Support Document 

UMRA Unfunded Mandates Reform Act 

VMT Vehicle Miles Traveled 

VOCs Volatile Organic Compounds 

WRAP Western Regional Air Partnership 

WRF Weather Research and Forecasting 

Table of Contents 

I. Executive Summary 

A. Purpose of Regulatory Action 

1. Emissions Limitations for EGUs 

Established by the Proposed Rule 

2. Emissions Limitations for Non-EGU 

Stationary Point Sources Established by 

the Proposed Rule 

3. Proposed Error Correction for Previously 

Approved 2015 Ozone Transport SIP 

4. Request for Comment on All Aspects of 

the Proposal 

B. Summary of the Major Provisions of the 

Regulatory Action 

C. Benefits and Costs 

II. Public Participation 

A. Written Comments 

B. Submitting Confidential Business 

Information 

C. Participation in Virtual Public Hearing 

III. General Information 

A. Does this action apply to me? 

B. What action is the Agency taking? 

C. What is the Agency’s legal authority for 

taking this action? 

1. Statutory Authority 

D. What actions has EPA previously issued 

to address regional ozone transport? 

IV. Air Quality Issues Addressed and Overall 

Approach for the Proposed Rule 

A. The Interstate Ozone Transport Air 

Quality Challenge 

1. Nature of Ozone and the Ozone NAAQS 

2. Ozone Transport 

3. Health and Environmental Effects 

B. Proposed Rule Approach 

1. The 4-Step Interstate Transport 

Framework 

a. Step 1 Approach 

b. Step 2 Approach 

c. Step 3 Approach 

d. Step 4 Approach 

2. FIP Authority for Each State Covered by 

the Proposed Rule 

C. Other CAA Authorities for This Action 

1. Correction of EPA’s Determination 

Regarding Delaware’s SIP Submission 

and Its Impact on EPA’s FIP Authority 

for Delaware 

2. Application of Rule in Indian Country 

and Necessary or Appropriate Finding 

a. Indian Country Subject to State 

Implementation Planning Authority 

V. Analyzing Downwind Air Quality 

Problems and Contributions From 

Upwind States 

A. Selection of Analytic Years for 

Evaluating Ozone Transport 

Contributions to Downwind Air Quality 

Problems 

B. Overview of Air Quality Modeling 

Platform 

C. Emissions Inventories 

1. Foundation Emissions Inventory Data 

Sets 

2. Development of Emissions Inventories 

for EGUs 

3. Development of Emissions Inventories 

for Non-EGU Point Sources 

4. Development of Emissions Inventories 

for Onroad Mobile Sources 

5. Development of Emissions Inventories 

for Commercial Marine Vessels 

6. Development of Emissions Inventories 

for Other Nonroad Mobile Sources 

7. Development of Emissions Inventories 

for Nonpoint Sources 

D. Air Quality Modeling To Identify 

Nonattainment and Maintenance 

Receptors 

E. Pollutant Transport From Upwind States 

1. Air Quality Modeling To Quantify 

Upwind State Contributions 

2. Application of Contribution Screening 

Threshold 

a. States That Contribute at or Above the 

Screening Threshold 

F. Treatment of Certain Receptors in 

California and Implications for Oregon’s 

Good Neighbor Obligations for 2015 

Ozone NAAQS 

VI. Quantifying Upwind-State NOX

Emissions Reduction Potential To 

Reduce Interstate Ozone Transport for 

the 2015 Ozone NAAQS 

A. The Multi-Factor Test for Determining 

Significant Contribution 

B. Identifying Control Stringency Levels 

1. EGU NOX Mitigation Strategies 

a. Optimizing Existing SCRs 

b. Installing State-of-the-Art NOX

Combustion Controls 

c. Optimizing Already Operating SNCRs or 

Turning on Idled Existing SNCRs 

d. Installing New SNCRs 

e. Installing New SCRs 

f. Generation Shifting 

2. Non-EGU NOX Mitigation Strategies 

a. Determining Non-EGU NOX Reduction 

Potential 

3. Other Stationary Sources NOX

Mitigation Strategies 

a. Units Less Than or Equal to 25 MW 

b. Municipal Solid Waste Units 

c. Cogeneration Units 

4. Mobile Source NOX Mitigation Strategies 

C. Control Stringencies Represented by 

Cost Threshold ($ per Ton) and 

Corresponding Emissions Reductions 

1. EGU Emissions Reduction Potential by 

Cost Threshold 

2. Non-EGU Emissions Reduction 

Potential—Cost Threshold Up to $7,500/ 

Ton 

D. Assessing Cost, EGU and Non-EGU NOX

Reductions, and Air Quality 

1. EGU Assessment 

2. Non-EGU Assessment 

a. Request for Comment on Non-EGU 

Control Strategies and Measures 

3. Combined EGU and Non-EGU 

Assessment 

4. Over-Control Analysis 

VII. Implementation of Emissions Reductions 

A. NOX Reduction Implementation 

Schedule 

1. 2023–2025: EGU NOX Reductions 

Beginning in 2023 

2. 2026 and Later Years: EGU and NonEGU EGU NOX Reductions Beginning in 

2026 

a. EGU Schedule for 2026 and Later Years 

b. Non-EGU Schedule for 2026 and Later 

Years 

B. Regulatory Requirements for EGUs 

1. Trading Program Background and 

Overview of Proposed Revisions 

a. Current CSAPR Trading Program Design 

Elements and Identified Concerns 

b. Enhancements To Maintain Selected 

Control Stringency Over Time 

i. Revised Emissions Budget-Setting 

Process 

ii. Allowance Bank Recalibration 

c. Enhancements To Improve Emissions 

Performance at Individual Units 

i. Unit-Specific Backstop Daily Emissions 

Rates 

ii. Unit-Specific Emissions Limitations 

Contingent on Assurance Level 

Exceedances 

2. Expansion of Geographic Scope 

3. Applicability and Tentative 

Identification of Newly Affected Units 

4. New and Revised State Emissions 

Budgets 

a. Methodology for Determining Preset 

State Emissions Budgets for the 2023 and 

2024 Control Periods 

b. Methodology for Determining Dynamic 

State Emissions Budgets for Control 

Periods in 2025 and Beyond 

c. Proposed and Illustrative State 

Emissions Budgets 

5. Variability Limits and Assurance Levels 

6. Annual Recalibration of Allowance Bank 

7. Unit-Specific Backstop Daily Emissions 

Rates 

8. Unit-Specific Emissions Limitations 

Contingent on Assurance Level 

Exceedances 

9. Unit-Level Allowance Allocation and 

Recordation Procedures 

a. Set-Asides of Portions of State Emissions 

Budgets for New Units 

b. Allocations to Existing Units, Including 

Units That Cease Operation 

c. Allocations From Portions of State 

Emissions Budgets Set Aside for New 

Units 

d. Incorrectly Allocated Allowances 

10. Other Trading Program Provisions 

a. Designated Representative Requirements 

b. Monitoring and Reporting Requirements 

11. Transitional Provisions 

a. Prorating Emissions Budgets, Assurance 

Levels, and Unit-Level Allowance 


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20038 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

1See 80 FR 65291 (October 26, 2015). 

2 In general, specific tribal names or reservations 

are not identified separately in this proposal except 

as needed. See Section IV.C.2 of this notice for 

further discussion. 

3As explained in Section VI.C.1 of this notice, 

EPA proposes finding that EGU sources within the 

State of California are sufficiently controlled such 

that no further emissions reductions are needed 

from them to eliminate significant contribution to 

downwind states. 

Allocations in the Event of an Effective 

Date After May 1, 2023 

b. Creation of Additional Group 3 

Allowance Bank for 2023 Control Period 

c. Recall of Group 2 Allowances for Control 

Periods After 2022 

12. Conforming Revisions to Other 

Regulations 

C. Regulatory Requirements for Non-EGUs 

1. Pipeline Transportation of Natural Gas 

2. Cement and Concrete Product 

Manufacturing 

3. Iron and Steel Mills and Ferroalloy 

Manufacturing 

4. Glass and Glass Product Manufacturing 

5. Boilers From Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills 

a. Coal-Fired Industrial Boilers 

b. Oil-Fired Industrial Boilers 

c. Gas-Fired Industrial Boilers 

D. Submitting a SIP 

1. SIP Option To Modify Allocations for 

2024 Under EGU Trading Program 

2. SIP Option To Modify Allocations for 

2025 and Beyond Under EGU Trading 

Program 

3. SIP Option To Replace the Federal EGU 

Trading Program With an Integrated 

State EGU Trading Program 

4. SIP Revisions That Do Not Use the New 

Trading Program 

5. SIP Revision Requirements for Non-EGU 

Emissions Limits 

E. Title V Permitting 

F. Relationship to Other Emissions Trading 

and Ozone Transport Programs 

1. NOX SIP Call 

2. Acid Rain Program 

3. Other Current Emissions Trading 

Programs 

VIII. Environmental Justice Considerations, 

Implications, and Stakeholder Outreach 

A. Introduction 

B. Analytical Considerations 

C. Outreach and Engagement 

IX. Costs, Benefits, and Other Impacts of the 

Proposed Rule 

X. Summary of Proposed Changes to the 

Regulatory Text for the Federal 

Implementation Plans and Trading 

Programs for EGUs 

A. Amendments to FIP Provisions in 40 

CFR Part 52 

B. Amendments to Group 3 Trading 

Program and Related Regulations 

C. Transitional Provisions 

D. Clarifications and Conforming Revisions 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Determinations Under CAA Section 

307(b)(1) and (d) 

I. Executive Summary 

This proposed rule would resolve the 

interstate transport obligations of 26 

states under CAA section 

110(a)(2)(D)(i)(I), referred to as the 

‘‘good neighbor provision’’ or the 

‘‘interstate transport provision’’ of the 

Act, for the 2015 ozone NAAQS. On 

October 1, 2015, the EPA revised the 

primary and secondary 8-hour standards 

for ozone to 70 parts per billion (ppb).1

States were required to provide ozone 

infrastructure State Implementation 

Plan (SIP) submissions to fulfill 

interstate transport obligations for the 

2015 ozone NAAQS by October 1, 2018. 

The EPA proposes to make a finding 

that interstate transport of ozone 

precursor emissions from 26 upwind 

states (Alabama, Arkansas, California, 

Delaware, Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, 

Minnesota, Mississippi, Missouri, 

Nevada, New Jersey, New York, Ohio, 

Oklahoma, Pennsylvania, Tennessee, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming) is 

significantly contributing to downwind 

nonattainment or interfering with 

maintenance of the 2015 ozone NAAQS 

in other states, based on projected 

nitrogen oxides (NOX) emissions in the 

2023 ozone season. The EPA is 

proposing to issue FIP requirements to 

eliminate interstate transport of ozone 

precursors from these 26 states that 

significantly contributes to 

nonattainment or interferes with 

maintenance of the NAAQS in other 

states. 

The EPA is proposing FIPs for 23 

states for which the Agency has not 

approved an ozone transport SIP that 

was submitted for the 2015 ozone 

NAAQS: Alabama, Arkansas, California, 

Illinois, Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Tennessee, Texas, Utah, West Virginia, 

Wisconsin, and Wyoming. In this 

proposed rule, the EPA is proposing to 

issue FIPs for two states—Pennsylvania 

and Virginia—for which the EPA issued 

a Finding of Failure to Submit for 2015 

ozone transport SIPs with an effective 

date of January 6, 2020. Under CAA 

section 301(d)(4), the EPA proposes to 

extend FIP requirements to apply in 

Indian country located within the 

upwind geography of the proposed rule, 

including Indian reservation lands and 

other areas of Indian country over 

which the EPA or a tribe has 

demonstrated that a tribe has 

jurisdiction.2 The EPA is also proposing 

a FIP for Delaware and an error 

correction for the Agency’s May 1, 2020, 

approval at 85 FR 25307 of the interstate 

transport elements for Delaware’s 

October 11, 2018, and December 26, 

2019, ozone infrastructure SIP 

submissions. 

In this proposed rule, the EPA 

proposes to establish new ozone season 

NOX emissions budgets beginning in 

2023 for Electric Generating Unit (EGU) 

sources. The EPA is also proposing to 

establish emissions limitations 

beginning in 2026 for certain other 

industrial stationary sources (referred to 

generally as ‘‘non-Electric Generating 

Units’’ (non-EGUs)). Taken together, 

these strategies will fully eliminate the 

covered states’ significant contribution 

to downwind ozone air quality 

problems in other states. 

The EPA proposes to implement the 

necessary emissions reductions as 

follows. The proposed FIP requirements 

establish ozone season NOX emissions 

budgets for EGUs in 25 states (Alabama, 

Arkansas, Delaware, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Pennsylvania, 

Tennessee, Texas, Utah, Virginia, West 

Virginia, Wisconsin, and Wyoming) and 

require EGUs in these states to 

participate in a revised version of the 

Cross-State Air Pollution Rule (CSAPR) 

NOX Ozone Season Group 3 Trading 

Program that was previously established 

in the Revised CSAPR Update.3 The 

EPA proposes to amend existing FIPs for 

12 states currently participating in the 

CSAPR NOX Ozone Season Group 3 

Trading Program (Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, New Jersey, New York, Ohio, 

Pennsylvania, Virginia, and West 

Virginia) to replace their existing 

emissions budgets established in the 

Revised CSAPR Update (with respect to 

the 2008 ozone NAAQS) with new 


lotter on DSK11XQN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20039 

4Bergin, 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. 

5Liao, 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. 

6See 82 FR 51238, 51248 (November 3, 2017) 

[citing 76 FR 48208, 48222 (August 8, 2011)] and 

63 FR 57381 (October 27, 1998). 

7 42 U.S.C. 7410(a)(2)(D)(i)(I). 

emissions budgets. For eight states 

currently covered by the CSAPR NOX

Ozone Season Group 2 Trading Program 

under SIPs or FIPs, the EPA is 

proposing to issue new FIPs for two 

states (Alabama and Missouri) and 

amend existing FIPs for six states 

(Arkansas, Mississippi, Oklahoma, 

Tennessee, Texas, and Wisconsin) to 

transition EGU sources in these states 

from the Group 2 program to the revised 

Group 3 trading program, beginning 

with the 2023 ozone season. EPA 

proposes to issue new FIPs for five 

states not currently covered by any 

CSAPR NOX ozone season trading 

program: Delaware, Minnesota, Nevada, 

Utah, and Wyoming. 

Under this proposed rulemaking, 

emissions reductions in the selected 

control stringency would be achieved as 

soon as they are available, some of 

which are scheduled to occur by the 

2023 ozone season and prior to the 

August 3, 2024, attainment date for 

areas classified as Moderate 

nonattainment for the 2015 ozone 

NAAQS, and the rest of which occur as 

soon as possible thereafter through the 

2026 ozone season, prior to the August 

3, 2027, attainment date for areas 

classified as Serious nonattainment for 

the 2015 ozone NAAQS. As discussed 

in Section VII.A.2 of this notice, the 

EPA proposes to find that the 2026 

ozone season is as expeditious as 

practicable to implement substantial 

emissions reductions from potential 

new post-combustion control 

installations at EGUs as well as from 

installation of new pollution controls at 

non-EGUs. 

These EGU emissions reductions are 

scheduled to begin in the 2026 ozone 

season based on the feasibility of control 

installation for EGUs in 22 states that 

remain linked to downwind 

nonattainment and maintenance 

receptors in that year. These 22 states 

are: Arkansas, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Pennsylvania, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming. The 

additional emissions reductions 

required for these states are based 

primarily on the potential retrofit of 

additional post-combustion controls for 

NOX on most coal steam EGUs and a 

portion of oil/gas steam EGUs that are 

currently lacking such controls. 

In this proposed rule, the EPA 

introduces additional features to the 

allowance-based trading program 

approach for EGUs, including dynamic 

adjustments of the emissions budgets 

over time and backstop daily emissions 

rate limits for most coal-fired units, that 

will help maintain control stringency 

over time and improve emissions 

performance at individual units, 

providing further assurance that existing 

pollution controls will be operated 

during the ozone season and that the 

emission reductions necessary to meet 

good neighbor requirements will be 

achieved. 

The EPA proposes to find that NOX

emissions from non-EGU sources are 

significantly contributing to 

nonattainment or interfering with 

maintenance of the 2015 ozone NAAQS 

and that cost-effective controls for NOX

emissions reductions are available in 

certain industrial source categories that 

would result in meaningful air quality 

improvements in downwind receptors. 

The EPA proposes to require emissions 

limitations beginning in 2026 for nonEGUs located within 23 states: 

Arkansas, California, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Pennsylvania, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming. The 

proposed rule establishes NOX

emissions limitations during the ozone 

season for the following unit types for 

sources in non-EGU industries: 

Reciprocating internal combustion in 

Pipeline Transportation of Natural Gas 

sources; kilns in Cement and Cement 

Product Manufacturing sources; boilers 

and furnaces in Iron and Steel Mills and 

Ferroalloy Manufacturing sources; 

furnaces in Glass and Glass Product 

Manufacturing sources; and highemitting equipment and large boilers in 

Basic Chemical Manufacturing, 

Petroleum and Coal Products 

Manufacturing, and Pulp, Paper, and 

Paperboard Mills. 

A. Purpose of the Regulatory Action 

The purpose of this rulemaking is to 

protect public health and the 

environment by reducing interstate 

transport of certain air pollutants that 

significantly contribute to 

nonattainment, or interfere with 

maintenance, of the 2015 ozone NAAQS 

in other states. Ground-level ozone has 

detrimental effects on human health as 

well as vegetation and ecosystems. 

Acute and chronic exposure to ozone in 

humans is associated with premature 

mortality and a number of morbidity 

effects, such as asthma exacerbation. 

Ozone exposure can also negatively 

impact ecosystems by limiting tree 

growth, causing foliar injury, and 

changing ecosystem community 

composition. Section IV of this 

proposed rule provides additional 

evidence of the harmful effects of ozone 

exposure on human health and the 

environment. Studies have established 

that ozone air pollution can be 

transported over hundreds of miles, 

with elevated ground-level ozone 

concentrations occurring in rural and 

metropolitan areas.4 5 Assessments of 

ozone control approaches have 

concluded that control strategies 

targeting reduction of NOX emissions 

are an effective method to reduce 

regional-scale ozone transport.6

CAA section 110(a)(2)(D)(i)(I) requires 

states to prohibit emissions that will 

contribute significantly to 

nonattainment or interfere with 

maintenance in any other state with 

respect to any primary or secondary 

NAAQS.7 States fulfill their primary 

responsibility to address interstate 

transport emissions under the good 

neighbor provision by submitting SIPs 

containing enforceable emission 

limitations and other control measures, 

means, or techniques required to 

address the interstate transport 

provision. Within 3 years of the EPA 

promulgating a new or revised NAAQS, 

states are required to provide 

infrastructure SIP submittals, including 

good neighbor SIPs. See CAA section 

110(a)(1) and (2). When states do not 

submit approvable interstate transport 

SIPs or fail to submit interstate transport 

SIPs by the statutory deadline, the CAA 

requires the EPA to issue FIPs to ensure 

that states eliminate their significant 

contribution to downwind air quality 

problems under the good neighbor 

provision. See generally CAA section 

110(k) and 110(c). As such, in this 

proposed rule, the EPA is proposing 

requirements to fully address good 

neighbor obligations for these states for 

the 2015 ozone NAAQS under its 

authority to promulgate FIPs under CAA 

section 110(c). 

It is appropriate to issue this proposal 

at this time for at least three reasons. 

First, this proposal will ensure that 

necessary emissions reductions to 

eliminate significant contribution are 

achieved as expeditiously as 

practicable. The EPA’s anticipated 

timing will provide for all possible 

emissions reductions to go into effect 


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20040 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

8Six of these eight states (Arkansas, Mississippi, 

Oklahoma, Tennessee, Texas, and Wisconsin) 

currently participate in the federal Group 2 trading 

program pursuant to the FIPs finalized in the 

CSAPR Update, so the FIPs proposed in this 

rulemaking would amend the existing FIPs for these 

beginning in the 2023 ozone season, 

which is aligned with the next 

upcoming attainment date of August 3, 

2024, for areas classified as Moderate 

nonattainment under the 2015 ozone 

standard. Additional emissions 

reductions that the EPA finds not 

possible to implement by that 

attainment date are proposed to take 

effect as expeditiously as practicable, 

with the full suite of emissions 

reductions taking effect by the 2026 

ozone season, which is aligned with the 

August 3, 2027, attainment date for 

areas classified as Serious 

nonattainment under the 2015 ozone 

NAAQS. As explained in sections V.A, 

VI, and VII.A of this proposed rule, 

these proposed timeframes for 

eliminating significant contribution are 

consistent with the provisions of title I 

of the CAA. Second, this proposal will 

provide states with as much information 

as the EPA can supply at this time to 

support their ability to submit SIP 

revisions to achieve the emissions 

reductions the EPA believes necessary 

to eliminate significant contribution. 

Third, for all of the states included in 

this proposed rule, the EPA’s modeling 

and analysis indicate that additional 

emissions reductions beyond those 

which are provided in any state’s 2015 

ozone transport SIP are necessary to 

eliminate significant contribution. 

The EPA anticipates that the states 

covered in this proposed FIP 

rulemaking may not have adequate 

provisions in their SIPs to address their 

interstate transport obligations for the 

2015 ozone NAAQS. As discussed in 

Section IV.B.2 of this proposed rule, the 

EPA has, for certain states, made 

findings that the state failed to submit 

a complete good neighbor SIP revision 

for the 2015 ozone NAAQS. For certain 

other states, the EPA has proposed, but 

has not finalized, actions disapproving 

good neighbor SIP revisions. And for 

other states, the EPA has not yet 

proposed action on their good neighbor 

SIP submittals, but these submittals are 

currently under review, and EPA 

intends to act on these submittals in the 

coming months. The EPA will not 

finalize this proposed FIP action for any 

state for which it has not taken final 

action either disapproving that state’s 

good neighbor SIP submittal or finding 

that the state failed to submit a complete 

SIP. 

The EPA conducted air quality 

modeling for future analytic years to 

identify (1) the downwind areas that are 

expected to have trouble attaining or 

maintaining the 2015 ozone NAAQS in 

the future and (2) the contribution of 

ozone transport from upwind states to 

the downwind air quality problems. 

Section V of this proposed rule provides 

a full description of the results of EPA’s 

air quality modeling and relevant 

analyses for the proposed rulemaking. 

Based on EPA’s air quality analysis, a 

total of 27 upwind states are linked 

above the 1 percent of the NAAQS 

threshold to downwind air quality 

problems in other states. The EPA had 

previously approved 2015 ozone 

transport SIPs submitted by two of these 

states—Oregon and Delaware—and 

proposes in this proposed rule to issue 

an error correction for its prior approval 

of Delaware’s 2015 ozone transport SIP 

(see Section IV.C.1 of this notice for 

additional information on the proposed 

error correction). The EPA is not 

proposing any change to its prior 

approval of Oregon’s 2015 ozone 

transport SIP, a determination which is 

further described in Section V.F of this 

proposed rule. 

In this proposed rule, the EPA is 

proposing to issue FIP requirements for 

26 states, which include emissions 

reductions for EGU sources within the 

borders of 25 states (described in 

Section VII.B of this proposed rule) and 

include emissions reductions for nonEGU sources within the borders of 23 

states (described in Section VII.C in this 

proposed rule). Based on EPA’s 

assessment of remaining air quality 

issues and additional emissions control 

strategies, the EPA further proposes to 

find that the EGU and non-EGU NOX

emissions reductions required in the 

proposed rule would fully eliminate 

these states’ significant contributions to 

downwind air quality problems for the 

2015 ozone NAAQS. By eliminating 

significant contribution from these 

upwind states, this rule, if finalized as 

proposed, will make substantial and 

meaningful improvements in air quality 

by reducing ozone levels at the 

identified downwind receptors as well 

as many other areas of the country. 

1. Emissions Limitations for EGUs 

Established by the Proposed Rule 

In this proposed rule, the EPA 

proposes to issue FIP requirements that 

include new NOX ozone season 

emissions budgets for EGU sources 

within the borders of the 25 states listed 

in Table I.A–1, with implementation of 

these emissions budgets beginning in 

the 2023 ozone season. The EPA 

proposes to find that these emissions 

reductions are necessary to address 

upwind states’ interstate transport 

obligations for the 2015 ozone NAAQS. 

TABLE I.A–1—PROPOSED LIST OF 25 

COVERED STATES FOR EGU EMISSIONS REDUCTIONS FOR THE 2015 

8-HOUR OZONE NAAQS 

State 

Alabama 

Arkansas 

Delaware 

Illinois 

Indiana 

Kentucky 

Louisiana 

Maryland 

Michigan 

Minnesota 

Mississippi 

Missouri 

Nevada 

New Jersey 

New York 

Ohio 

Oklahoma 

Pennsylvania 

Tennessee 

Texas 

Utah 

Virginia 

West Virginia 

Wisconsin 

Wyoming 

The EPA proposes to expand the 

CSAPR NOX Ozone Season Group 3 

Trading Program beginning in the 2023 

ozone season. Specifically, the FIPs 

would require power plants within the 

borders of the 25 states listed in Table 

I.A–1 to participate in a revised version 

of the CSAPR NOX Ozone Season Group 

3 Trading Program created by the 

Revised CSAPR Update. Affected EGUs 

within the borders of twelve states 

currently participating in the Group 3 

Trading Program under FIPs or SIPs 

would remain in the program, with 

revised provisions beginning in the 

2023 ozone season, under this proposed 

rule: Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, New 

Jersey, New York, Ohio, Pennsylvania, 

Virginia, and West Virginia. The FIPs 

would also require affected EGUs within 

the borders of eight states currently 

covered by the CSAPR NOX Ozone 

Season Group 2 Trading Program (the 

‘‘Group 2 trading program’’) under 

existing FIPs or existing SIPs to 

transition from the Group 2 program to 

the revised Group 3 trading program 

beginning with the 2023 control period: 

(Alabama, Arkansas, Mississippi, 

Missouri, Oklahoma, Tennessee, Texas, 

and Wisconsin).8 Finally, the EPA is 


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states. The other two states (Alabama and Missouri) 

have already replaced the FIPs finalized in the 

CSAPR Update with approved SIP revisions that 

require their EGUs to participate in state Group 2 

trading programs integrated with the federal Group 

2 trading program, so the FIPs proposed in this 

action would constitute new FIPs for these states, 

and the EPA would cease implementation of the 

state Group 2 trading programs included in the two 

states’ SIPs. 

9Two states, Kansas and Iowa, will remain in the 

Group 2 Trading Program. 

10See the Air Quality Modeling Technical 

Support Document (AQM TSD) in the docket for 

this proposed rule. 

proposing to issue new FIPs for EGUs 

within the borders of five states not 

currently covered by any CSAPR trading 

program for seasonal NOX emissions: 

Delaware, Minnesota, Nevada, Utah, 

and Wyoming. If the proposed FIP is 

finalized, sources in these states would 

enter the Group 3 trading program in the 

2023 control period following the 

effective date of the final rule.9 In all 

cases, if the state submits and the EPA 

approves a SIP revision that would fully 

achieve the emissions reductions 

needed to meet the state’s good neighbor 

obligations with respect to the 2015 

ozone NAAQS before a final rule is 

promulgated in this rulemaking, the 

proposed FIP requirements summarized 

above would not be finalized. Refer to 

Section VII.B of this proposed rule for 

details on EGU regulatory requirements. 

2. Emissions Limitations for Non-EGU 

Stationary Point Sources Established by 

the Proposed Rule 

In this proposed rule, the EPA 

proposes to issue FIP requirements that 

include new NOX emissions limitations 

for non-Electric Generating Unit (nonEGU) sources in 23 states, with earliest 

possible compliance dates for these 

emissions limitations beginning in 2026. 

The EPA proposes to require emissions 

reductions from non-EGU sources to 

address interstate transport obligations 

for the 2015 ozone NAAQS for the 23 

states listed in Table I.A–2. 

TABLE I.A–2—PROPOSED LIST OF 23 

COVERED STATES FOR NON-EGU 

EMISSIONS REDUCTIONS FOR THE

2015 8-HOUR OZONE NAAQS 

State 

Arkansas 

California 

Illinois 

Indiana 

Kentucky 

Louisiana 

Maryland 

Michigan 

Minnesota 

Mississippi 

Missouri 

Nevada 

New Jersey 

New York 

TABLE I.A–2—PROPOSED LIST OF 23 

COVERED STATES FOR NON-EGU 

EMISSIONS REDUCTIONS FOR THE

2015 8-HOUR OZONE NAAQS— 

Continued 

State 

Ohio 

Oklahoma 

Pennsylvania 

Texas 

Utah 

Virginia 

West Virginia 

Wisconsin 

Wyoming 

The EPA is proposing to require 

emissions limitations for the following 

unit types in non-EGU industries: 

Reciprocating internal combustion 

engines in Pipeline Transportation of 

Natural Gas sources; kilns in Cement 

and Cement Product Manufacturing 

sources; boilers and furnaces in Iron and 

Steel Mills and Ferroalloy 

Manufacturing sources; furnaces in 

Glass and Glass Product Manufacturing 

sources; and high-emitting equipment 

and large boilers in Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. Refer to 

Table III.A–1 for a list of North 

American Industry Classification 

System (NAICS) codes for each entity 

included for regulation under this 

proposed rule. 

3. Proposed Error Correction for 

Previously Approved 2015 Ozone 

Transport SIP 

The EPA proposes to make an error 

correction under CAA section 110(k)(6) 

of its May 1, 2020, approval at 85 FR 

25307 of the interstate transport 

elements for Delaware’s October 11, 

2018, and December 26, 2019, ozone 

infrastructure SIP submissions as 

satisfying the requirements of CAA 

section 110(a)(2)(D)(i)(I) for the 2015 

ozone NAAQS. The EPA proposes to 

determine that the basis for the prior SIP 

approval is invalidated by the Agency’s 

more recent technical evaluation of air 

quality modeling performed in support 

of the proposed rule,10 and that 

Delaware has unresolved interstate 

transport obligations for the 2015 ozone 

NAAQS. In this proposed rule, the EPA 

is also exercising its authority to 

propose to issue a FIP for Delaware in 

light of these unresolved interstate 

transport obligations. 

4. Request for Comment on All Aspects 

of the Proposal 

Throughout this proposed rule, unless 

noted otherwise, the EPA is requesting 

comments on all aspects of the proposal 

to enable the Agency to develop a final 

rule that, consistent with our 

responsibilities under section 110 of the 

CAA, eliminates air pollution that 

significantly contributes to 

nonattainment or interference with 

maintenance of the 2015 ozone NAAQS. 

This proposed rule adheres closely to 

the legal and analytical framework that 

the EPA has applied in the past in 

implementing the good neighbor 

provision of the CAA, as well as the 

ample case law reviewing that 

framework. At the same time, in this 

proposal, the EPA is applying lessons 

learned from the performance of 

regulatory programs established by 

previous ozone transport rulemakings, 

as well as updating the Agency’s 

application of the 4-step interstate 

transport framework with recent 

information on the nature of ozone 

transport and emissions reductions 

opportunities in order to eliminate 

significant contribution for the more 

stringent 2015 ozone NAAQS under the 

good neighbor provision. The EPA 

invites comments and information to 

support its efforts to improve the 

regulation of interstate ozone transport 

under the good neighbor provision and 

to fulfill our mission to protect human 

health and the environment. The EPA 

will carefully consider information 

provided in response to this request and 

will respond to comments submitted 

through the regulatory docket in the 

final rule. 

B. Summary of the Major Provisions of 

the Regulatory Action 

The EPA is applying the 4-step 

interstate transport framework 

developed in CSAPR, the CSAPR 

Update, the Revised CSAPR Update, 

and other previous ozone transport rules 

to propose to further limit NOX

emissions from EGU sources within the 

borders of 25 states during the ozone 

season (May 1 through September 30) 

and to limit ozone season NOX

emissions from non-EGU sources in 23 

states to reduce interstate ozone 

transport under the authority provided 

in CAA section 110(a)(2)(D)(i)(I). The 4- 

step interstate transport framework 

provides a stepwise method for the EPA 

to propose rule provisions that are 

required to address the requirements of 

the good neighbor provision for the 

2015 ozone NAAQS: (1) Identifying 

downwind receptors that are expected 

to have problems attaining or 


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11These 3 analytic years are the last full ozone 

seasons before, and thus align with, upcoming 

attainment dates for the 2015 ozone NAAQS: 

August 3, 2024, for areas classified as Moderate 

nonattainment, August 3, 2027, for areas classified 

as Serious nonattainment, and August 3, 2033, for 

areas classified as Severe. See 83 FR 25776. 

12The EPA did not perform contribution 

modeling for 2032 since contribution data for this 

year were not needed to identify upwind states to 

be analyzed in Step 3. 

13See Section V of this proposed rule for 

explanation of EPA’s use of the 1 percent of the 

NAAQS threshold in the Step 2 analysis. 

maintaining the NAAQS; (2) 

determining which upwind states 

contribute to these identified problems 

in amounts sufficient to ‘‘link’’ them to 

the downwind air quality problems (i.e., 

in this proposed rule, a contribution 

threshold of 1 percent of the NAAQS); 

(3) for states linked to downwind air 

quality problems, identifying upwind 

emissions that significantly contribute 

to downwind nonattainment or interfere 

with downwind maintenance of the 

NAAQS; and (4) for states that are found 

to have emissions that significantly 

contribute to nonattainment or interfere 

with maintenance of the NAAQS in 

downwind areas, implementing the 

necessary emissions reductions through 

enforceable measures. In this proposed 

rule, the EPA applies the 4-step 

framework to evaluate upwind states’ 

obligations to reduce interstate transport 

of ozone precursor emissions for the 

2015 ozone NAAQS. The remainder of 

this section provides a general overview 

of the EPA’s application of the 4-step 

framework as it applies to major 

provisions of the proposed rule; 

additional details regarding EPA’s 

proposed rule approach are found in 

Section IV of this proposed rule. 

In order to apply the first step of the 

4-step framework to the 2015 ozone 

NAAQS, the EPA performed air quality 

modeling to project ozone 

concentrations at air quality monitoring 

sites in 2023, 2026, and 2032.11 The 

EPA evaluated projected ozone 

concentrations for the 2023 analytic 

year at individual monitoring sites and 

considered current ozone monitoring 

data at these sites to identify receptors 

that are anticipated to have problems 

attaining or maintaining the 2015 ozone 

NAAQS. This analysis was then 

repeated using projected ozone 

concentrations for 2026 and 2032. 

To apply the second step of the 

framework, the EPA used air quality 

modeling to quantify the contributions 

from upwind states to ozone 

concentrations in 2023 and 2026 at 

downwind receptors.12 Once quantified, 

EPA then evaluated these contributions 

relative to a screening threshold of 1 

percent of the NAAQS (i.e., 0.70 ppb).13

States with contributions that equaled 

or exceeded 1 percent of the NAAQS 

were identified as warranting further 

analysis at Step 3 of the four-step 

framework to determine if the upwind 

state significantly contributes to 

nonattainment or interference with 

maintenance in a downwind state. 

States with contributions below 1 

percent of the NAAQS were considered 

not to significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in 

downwind states. Based on EPA’s most 

recent air quality modeling and 

contribution analysis using 2023 as the 

analytic year, the EPA proposes to find 

that the following 27 states have 

contributions that equal or exceed 1 

percent of the 2015 ozone NAAQS, and, 

thereby, warrant further analysis of 

significant contribution to 

nonattainment or interference with 

maintenance of the NAAQS: Alabama, 

Arkansas, California, Delaware, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Oregon, Pennsylvania, Tennessee, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming. Further 

evaluation of the locations in California 

to which Oregon was linked at Step 2 

leads the EPA to conclude downwind 

areas represented by these monitoring 

sites should not be considered interstate 

ozone transport receptors. Therefore, the 

EPA is not proposing any further 

emissions reductions from the state of 

Oregon because there is no significant 

contribution required to be eliminated 

under the interstate transport provision, 

as described in Section V.F of this 

proposed rule. 

Based on the air quality analysis 

presented in Section V of this proposed 

rule, the EPA proposes to find that in 

the absence of additional emissions 

reductions in those states the majority of 

the states that the EPA is proposing to 

participate in the Ozone Season Group 

3 Trading Program will continue to 

contribute above the 1 percent of the 

NAAQS threshold to at least one 

receptor whose nonattainment and 

maintenance concerns persist through 

the 2026 ozone season, with the 

exception of Alabama, Delaware, and 

Tennessee. As a result, EPA’s evaluation 

of emissions reduction potential at Step 

3 for Alabama, Delaware, and Tennessee 

is limited to emission reductions 

achievable by the 2023 ozone season. 

For each of these three states, EPA’s 

analysis does not consider, nor does the 

EPA propose to require, emissions 

reductions at either EGUs or non-EGUs 

that cannot be implemented until the 

2026 ozone season. 

At the third step of the 4-step 

framework, EPA applied a multi-factor 

test that incorporates cost, availability of 

emissions reductions, and air quality 

impacts at the downwind receptors to 

determine the amount of ozone 

precursor emissions from the linked 

upwind states that ‘‘significantly’’ 

contribute to downwind nonattainment 

or maintenance receptors. In this 

proposed rule, the EPA proposes to 

apply the multifactor test described in 

Section VI.A of this proposed rule to 

both EGU and non-EGU sources. The 

EPA assessed the potential emissions 

reductions in 2023 and 2026, as well as 

in intervening and later years to 

determine the emissions reductions 

required to eliminate significant 

contribution in any future year where 

downwind areas are projected to have 

potential problems attaining or 

maintaining the 2015 ozone NAAQS. 

For EGU sources, the EPA evaluated 

the following set of widely-available 

NOX emissions control technologies: (1) 

Fully operating existing selective 

catalytic reduction (SCR) controls, 

including both optimizing NOX removal 

by existing operational SCRs and 

turning on and optimizing existing idled 

SCRs; (2) installing state-of-the-art NOX

combustion controls; (3) fully operating 

existing selective non-catalytic 

reduction (SNCR) controls, including 

both optimizing NOX removal by 

existing operational SNCRs and turning 

on and optimizing existing idled 

SNCRs; (4) installing new SNCRs; (5) 

installing new SCRs; and (6) generation 

shifting. For the reasons explained in 

Section VI of this proposed rule and 

supported by the EGU NOX Mitigation 

Strategies Proposed Rule Technical 

Support Document (TSD) included in 

the docket for this proposed rule, the 

EPA determined that for the regional, 

multi-state scale of this rulemaking, 

only fully operating and optimizing 

existing SCRs and existing SNCRs (EGU 

NOX emissions controls options 1 and 3 

in the list earlier) are possible for the 

2023 ozone season. The EPA 

determined that state-of-the-art NOX

combustion controls at EGUs (emissions 

control option 2 in the list above) are 

available by the beginning of the 2024 

ozone season. Based on EPA’s 

assessment of the earliest possible 

timeframe for installation of new SNCR 

and SCRs (EGU emissions controls 

options 4 and 5 in the list), the EPA 

proposes to require emissions 

reductions commensurate with these 

controls by the beginning of the 2026 

ozone season. See Section VI.B.1 of this 

proposed rule for a full description of 


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14See, e.g., 70 FR 25162, 25205–06 (May 12, 

2005). 

EPA’s analysis of NOX emissions 

mitigation strategies for EGU sources. 

The EPA proposes control stringency 

levels that maximize incremental NOX

emissions reduction potential from 

EGUs and corresponding downwind 

ozone air quality improvements to the 

extent feasible in each year analyzed. 

The EPA believes that the required 

controls provide cost-effective 

reductions of NOX emissions that will 

provide substantial improvements in 

downwind ozone air quality to address 

interstate transport obligations for the 

2015 ozone NAAQS in a timely manner. 

These controls represent greater 

stringency in upwind EGU controls than 

in EPA’s most recent ozone transport 

rulemakings, such as the CSAPR Update 

and the Revised CSAPR Update. 

However, programs to address interstate 

ozone transport based on the retrofit of 

post-combustion controls are by no 

means unprecedented. In prior ozone 

transport rulemakings such as the NOX

SIP Call and the Clean Air Interstate 

Rule (CAIR), the EPA established EGU 

budgets premised on the widespread 

availability of retrofitting EGUs with 

post-combustion emissions controls 

such as SCR.14 While these programs 

successfully drove many EGUs to 

retrofit post-combustion controls, other 

EGUs throughout the present geography 

of linked upwind states continue to 

operate without such controls and 

continue to emit at relatively high rates 

more than 20 years after similar units 

reduced these emissions under prior 

interstate ozone transport rulemakings. 

Furthermore, the CSAPR Update 

provided only a partial remedy for 

eliminating significant contribution for 

the 2008 ozone NAAQS, as needed to 

obtain available reductions by the 2017 

ozone season. In that rule, the EPA 

made no determination regarding the 

appropriateness of more stringent EGU 

NOX controls that would be required for 

a full remedy for interstate transport for 

the 2008 ozone NAAQS. Following the 

remand of the CSAPR Update in 

Wisconsin v. EPA, 938 F.3d 303 (D.C. 

Cir. 2019) (Wisconsin), the EPA again 

declined to require the retrofit of new 

post-combustion controls on EGUs in 

the Revised CSAPR Update, but that 

determination was based on a specific 

timing consideration: Downwind air 

quality problems under the 2008 ozone 

NAAQS were projected to resolve before 

post-combustion control retrofits could 

be accomplished on a fleetwide, 

regional scale. See 86 FR 23054, 23110 

(April 30, 2021). 

In this proposed rulemaking, the EPA 

is addressing good neighbor obligations 

for the more stringent 2015 ozone 

NAAQS, and the Agency observes 

ongoing and persistent contribution 

from upwind states to ozone 

nonattainment and maintenance 

receptors in other states under that 

NAAQS. As further discussed in Section 

VI of this proposed rule, the nature of 

this contribution warrants a greater 

degree of control stringency than the 

EPA determined to be necessary to 

eliminate significant contribution of 

ozone transport in prior CSAPR 

rulemakings. The EPA is therefore 

returning to EGU NOX control strategies 

commensurate with those determined to 

be necessary in the NOX SIP Call and 

CAIR. 

Based on the Step 3 analysis 

described in Section VI of this proposed 

rule, the EPA is proposing that 

emissions reductions commensurate 

with the full operation of all existing 

post-combustion controls (both SCRs 

and SNCRs) and state-of-the-art 

combustion control upgrades constitute 

the Agency’s selected control stringency 

for EGUs within the borders of 25 states 

linked to downwind nonattainment or 

maintenance in 2023 (Alabama, 

Arkansas, Delaware, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Pennsylvania, 

Tennessee, Texas, Utah, Virginia, West 

Virginia, Wisconsin, and Wyoming). For 

22 of those states that are also linked in 

2026 (Arkansas, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Pennsylvania, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming), the EPA is 

determining that the selected EGU 

control stringency also includes 

emissions reductions commensurate 

with the retrofit of SCR at coal steam 

units of 100 MW or greater capacity 

(excepting circulating fluidized bed 

units (CFB)), new SNCR on coal steam 

units of less than 100 MW capacity and 

CFBs, and SCR on oil/gas steam units 

greater than 100 MW that have 

historically emitted at least 150 tons of 

NOX per ozone season. 

To identify appropriate control 

strategies for non-EGU sources to 

achieve NOX emissions reductions that 

would result in meaningful air quality 

improvements in downwind areas, the 

EPA developed an analytical framework 

to evaluate the air quality impacts of 

potential emissions reductions from 

non-EGU sources located in the linked 

upwind states. The EPA incorporated 

air quality modeling information, 

annual emissions, and information 

about potential controls to determine 

which industries, if subject to further 

control requirements, would have the 

greatest impact in providing air quality 

improvements at the downwind 

receptors. This evaluation was subject to 

a marginal cost threshold of up to 

$7,500 per ton, which the EPA 

determined based on information 

available to the Agency about existing 

control device efficiency and cost 

information. Additional information on 

the analytical framework is described in 

Section VI.B.2 of this proposed rule and 

is presented in the memorandum titled 

Screening Assessment of Potential 

Emissions Reductions, Air Quality 

Impacts, and Costs from Non-EGU 

Emissions Units for 2026 (‘‘Non-EGU 

Screening Assessment memorandum’’), 

which is available in the docket for this 

proposed rulemaking. Based on the 

results of this assessment, the EPA 

identified emissions unit types in seven 

industries (identified in Section I.A.2 of 

this proposed rule) that provide 

opportunities for NOX emissions 

reductions that result in meaningful 

impacts on air quality at the downwind 

receptors. 

The EPA performed air quality 

analysis using the Ozone Air Quality 

Assessment Tool (AQAT) to determine 

whether the proposed emissions 

reductions for both EGUs and non-EGUs 

potentially create an ‘‘over-control’’ 

scenario whereby (1) the expected ozone 

improvements would be greater than 

necessary to resolve the downwind 

ozone pollution problem (i.e., beyond 

what is necessary to resolve all 

nonattainment and maintenance 

problems to which an upwind state is 

linked) or (2) the expected ozone 

improvements would reduce the 

upwind state’s ozone contributions 

below the screening threshold (i.e., 1 

percent of the NAAQS or 0.70 ppb). The 

EPA’s over-control analysis, discussed 

in Section VI.D.4 of this proposed rule, 

shows that the proposed control 

stringencies for EGU and non-EGU 

sources do not over-control upwind 

states’ emissions either with respect to 

the downwind air quality problems to 

which they are linked or with respect to 

the 1 percent of the NAAQS 

contribution threshold, such that overcontrol would trigger re-evaluation at 

Step 3 for any linked upwind state. 


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15The EPA would deem participation in the 

Group 3 trading program by the EGUs in these eight 

states as also addressing the respective states’ good 

neighbor obligations with respect to the 2008 ozone 

NAAQS (for all eight states), the 1997 ozone 

NAAQS (for all the states except Texas), and the 

1979 ozone NAAQS (for Alabama, Missouri, and 

Tennessee) to the same extent that those obligations 

are currently being addressed by participation of 

the states’ EGUs in the Group 2 trading program. 

Based on the multi-factor test applied 

to both EGU and non-EGU sources and 

our subsequent assessment of overcontrol, the EPA finds that the selected 

EGU and non-EGU control stringencies 

constitute the elimination of significant 

contribution and interference with 

maintenance, without over-controlling 

emissions, from the 26 upwind states 

subject to EGU and non-EGU emissions 

reductions requirements under the 

proposed rule. In order to eliminate 

significant contribution and interference 

with maintenance through the fourth 

step of the 4-step framework, as 

described in Section VII of this 

proposed rule, the EPA is establishing 

emissions budgets for EGUs within the 

borders of 25 states that reflect the 

remaining allowable emissions after the 

emissions reductions associated with 

the selected control stringency have 

been achieved. For the same reason, the 

EPA is establishing non-EGU emissions 

limits in 23 states that result in the 

elimination of significant contribution 

from non-EGU sources in these states. 

For additional details about the test and 

the over-control analysis, see the 

document titled, ‘‘Ozone Transport 

Policy Analysis Proposed Rule TSD’’ 

included in the docket for this 

rulemaking. 

In this fourth step of the 4-step 

framework, the EPA proposes to include 

enforceable measures in the 

promulgated FIPs to achieve the 

required emissions reductions in each of 

the 26 states. Specifically, the FIPs 

would require covered power plants 

within the borders of the 25 states listed 

in Table I.A–1 to participate in the 

CSAPR NOX Ozone Season Group 3 

Trading Program created by the Revised 

CSAPR Update. Affected EGUs within 

the borders of twelve states currently 

participating in the Group 3 Trading 

Program would remain in the program, 

with revised provisions beginning in the 

2023 ozone season, under this proposed 

rule: Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, New 

Jersey, New York, Ohio, Pennsylvania, 

Virginia, and West Virginia. Affected 

EGUs within the borders of eight states 

currently covered by the CSAPR NOX

Ozone Season Group 2 Trading Program 

(the ‘‘Group 2 trading program’’)— 

Alabama, Arkansas, Mississippi, 

Missouri, Oklahoma, Tennessee, Texas, 

and Wisconsin—would transition from 

the Group 2 program to the revised 

Group 3 trading program beginning with 

the 2023 control period,15 and affected 

EGUs within the borders of five states 

not currently covered by any CSAPR 

trading program for seasonal NOX

emissions—Delaware, Minnesota, 

Nevada, Utah, and Wyoming—would 

enter the Group 3 trading program in the 

2023 control period following the 

effective date of the final rule. In 

addition, the EPA proposes to revise 

other aspects of the Group 3 trading 

program to help maintain control 

stringency over time and improve 

emissions performance at individual 

units, offering a necessary measure of 

assurance that existing pollution 

controls will be operated during the 

ozone season, as described in Section 

VII of this proposed rule. This proposal 

does not revise the budget stringency 

and geography of the existing CSAPR 

NOX Ozone Season Group 1 trading 

program. Aside from the eight states 

moving from the Group 2 trading 

program to the Group 3 trading program 

under the proposed rule, this proposal 

otherwise leaves unchanged the budget 

stringency of the existing CSAPR NOX

Ozone Season Group 2 trading program. 

The EPA is proposing preset ozone 

season NOX emissions budgets for the 

2023 and 2024 ozone seasons, as 

explained in Section VII.B of this 

proposed rule and as shown in Table 

I.B–1. 

TABLE I.B–1—PROPOSED AND ILLUSTRATIVE CSAPR NOX OZONE SEASON GROUP 3 STATE EMISSIONS BUDGETS FOR

2023 THROUGH 2026 CONTROL PERIODS * 

State 

Proposed 

emissions 

budgets for 

2023 control 

period 

(tons) 

Proposed 

emissions 

budgets for 

2024 control 

period 

(tons) 

Illustrative 

emissions 

budgets for 

2025 control 

period 

(tons) 

Illustrative 

emissions 

budgets for 

2026 control 

period 

(tons) 

Alabama ........................................................................................................... 6,364 6,306 6,306 6,306 

Arkansas .......................................................................................................... 8,889 8,889 8,889 3,923 

Delaware .......................................................................................................... 384 434 434 434 

Illinois ............................................................................................................... 7,364 7,463 7,463 6,115 

Indiana ............................................................................................................. 11,151 9,391 8,714 7,791 

Kentucky .......................................................................................................... 11,640 11,640 11,134 7,573 

Louisiana .......................................................................................................... 9,312 9,312 9,179 3,752 

Maryland .......................................................................................................... 1,187 1,187 1,187 1,189 

Michigan ........................................................................................................... 10,718 10,718 10,759 6,114 

Minnesota ........................................................................................................ 3,921 3,921 3,910 2,536 

Mississippi ........................................................................................................ 5,024 4,400 4,400 1,914 

Missouri ............................................................................................................ 11,857 11,857 10,456 7,246 

Nevada ............................................................................................................. 2,280 2,372 2,372 1,211 

New Jersey ...................................................................................................... 799 799 799 799

New York ......................................................................................................... 3,763 3,763 3,763 3,238 

Ohio ................................................................................................................. 8,369 8,369 8,369 8,586 

Oklahoma ......................................................................................................... 10,265 9,573 9,393 4,275 

Pennsylvania .................................................................................................... 8,855 8,855 8,855 6,819 

Tennessee ....................................................................................................... 4,234 4,234 4,008 4,008 

Texas ............................................................................................................... 38,284 38,284 36,619 21,946 

Utah ................................................................................................................. 14,981 15,146 15,146 2,620 

Virginia ............................................................................................................. 3,090 2,814 2,948 2,567 

West Virginia .................................................................................................... 12,478 12,478 12,478 10,597 

Wisconsin ......................................................................................................... 5,963 5,057 4,198 3,473 


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16See 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. 

TABLE I.B–1—PROPOSED AND ILLUSTRATIVE CSAPR NOX OZONE SEASON GROUP 3 STATE EMISSIONS BUDGETS FOR

2023 THROUGH 2026 CONTROL PERIODS *—Continued 

State 

Proposed 

emissions 

budgets for 

2023 control 

period 

(tons) 

Proposed 

emissions 

budgets for 

2024 control 

period 

(tons) 

Illustrative 

emissions 

budgets for 

2025 control 

period 

(tons) 

Illustrative 

emissions 

budgets for 

2026 control 

period 

(tons) 

Wyoming .......................................................................................................... 9,125 8,573 8,573 4,490 

* Further information on the state-level emissions budget calculations pertaining to Table I.B–1 is provided in Section VII.B.4 of this proposed 

rule as well as the Ozone Transport Policy Analysis Proposed Rule TSD. Further information on the proposed approach for allocating a portion 

of Utah’s emissions budget for each control period to the existing EGU in the Uintah and Ouray Reservation within Utah’s borders is provided in 

Section VII.B.9 of this proposed rule. 

Beyond preset emissions budgets for 

the 2023 and 2024 control periods, the 

EPA also proposes to extend the Group 

3 trading program budget-setting 

methodology used in the Revised 

CSAPR Update so as to routinely set 

emissions budgets for each future 

control period (beginning in 2025) in 

the year before that control period, with 

each emissions budget reflecting the 

latest available information on the 

composition and utilization of the EGU 

fleet at the time that emissions budget 

is determined (see Table VII.B.4.c–2 for 

illustrative examples of dynamic budget 

calculations that the EPA will publish 

in advance of each ozone season, 

effective for the 2025 control period and 

beyond). The stringency of the dynamic 

emissions budgets would simply reflect 

the stringency of the emissions control 

strategies selected in the rulemaking 

more consistently over time and ensure 

that the annual updates would eliminate 

emissions determined to be unlawful 

under the good neighbor provision. See 

Section VII.B of this proposed rule for 

additional discussion of EPA’s proposed 

method for adjusting emissions budgets 

to ensure elimination of significant 

contribution from EGU sources in the 

linked upwind states. 

As an enhancement to the structure of 

the trading program as originally 

promulgated in the Revised CSAPR 

Update, the EPA is also proposing to 

establish backstop daily emissions rates 

for coal steam units greater than or 

equal to 100 MW in covered states. 

Units emitting in excess of these daily 

rates would be subject to increased 

allowance surrender requirements 

under the trading program. The 

backstop daily emissions rates would 

work in tandem with the ozone season 

emissions budgets to offer downwind 

stakeholders a necessary measure of 

assurance that they will be protected on 

a daily basis during the ozone season by 

continuous operation of installed 

pollution controls. The EPA’s 

experience with the CSAPR trading 

programs has revealed instances where 

EGUs have reduced their SCRs’ 

performance on a given day, or across 

the entire ozone seasons in some cases, 

including high ozone days.16 In addition 

to maintaining a mass-based seasonal 

requirement, the EPA proposes to 

require controls while maintaining as 

much compliance flexibility as possible 

through a unit-level emission rate 

designed to ensure that controls operate 

continuously and that required 

reductions occur on the highest ozone 

days. These trading program 

improvements also promote consistent 

emissions control performance across 

the power sector, which protects 

communities living in downwind ozone 

nonattainment areas from exceedances 

of the NAAQS that might otherwise 

occur. 

The EPA proposes to include 

enforceable emissions standards that 

will apply during the ozone season 

(annually from May to September) for 

seven non-EGU industries in the 

promulgated FIPs to achieve the 

required emissions reductions in 23 

states with remaining interstate 

transport obligations for the 2015 ozone 

NAAQS in 2026: Arkansas, California, 

Illinois, Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Pennsylvania, Texas, Utah, Virginia, 

West Virginia, Wisconsin, and 

Wyoming. These requirements would 

apply to all existing emissions units and 

to any future emissions units 

constructed in the covered states after 

promulgation of the final rule. Thus, the 

emissions limits for non-EGU sources 

and associated compliance requirements 

would apply in all 23 states listed in 

this paragraph, even if certain of these 

states do not currently have existing 

emissions units within a particular 

industry. 

Based on our evaluation of the time 

required to install controls at the types 

of non-EGU sources covered by this 

proposed rule, the EPA has identified 

the 2026 ozone season as the earliest 

compliance date possible for non-EGU 

emissions reductions. The EPA is 

therefore proposing to include non-EGU 

emissions reductions beginning in 2026. 

For sources located in the 23 states 

listed in the previous paragraph, The 

EPA proposes to require the emissions 

limits listed in Table I.B–2 for 


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20046 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

17Based on source cap equation at 30 TAC 

§ 117.3123(b); January 14, 2009 (74 FR 1927), 

Docket ID No. EPA–R06–OAR–2007–1147, also see 

https://wayback.archive-it.org/414/ 

20210527223433/https://www.tceq.texas.gov/ 

assets/public/legal/rules/rules/pdflib/117e.pdf. 

reciprocating internal combustion 

engines in Pipeline Transportation of 

Natural Gas; the emissions limits listed 

in Table I.B–3 for kilns in Cement and 

Cement Product Manufacturing; the 

emissions limits listed in Table I.B–4 for 

boilers and furnaces in Iron and Steel 

Mills and Ferroalloy Manufacturing; the 

emissions limits listed in Table I.B–5 for 

furnaces in Glass and Glass Product 

Manufacturing; and the emissions limits 

listed in Table I.B–6 for high-emitting 

equipment and large boilers in Basic 

Chemical Manufacturing, Petroleum and 

Coal Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. 

TABLE I.B–2—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR

PIPELINE TRANSPORTATION OF NATURAL GAS

Engine type and fuel Proposed NOX

emissions limit 

Natural Gas Fired Four 

Stroke Rich Burn.

1.0 g/hp-hr. 

Natural Gas Fired Four 

Stroke Lean Burn.

1.5 g/hp-hr. 

Natural Gas Fired Two 

Stroke Lean Burn.

3.0 g/hp-hr. 

TABLE I.B–3—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR

KILN TYPES IN CEMENT AND CONCRETE PRODUCT MANUFACTURING

Kiln type 

Proposed NOX

emissions limit 

(lb/ton of 

clinker) 

Long Wet .............................. 4.0 

Long Dry ............................... 3.0 

Preheater .............................. 3.8 

Precalciner ............................ 2.3 

Preheater/Precalciner ........... 2.8 

The EPA is also proposing a source 

cap limit expressed in ton per day (tpd) 

of NOX for each individual cement plant 

according to the following equation.17

Where: 

CAP2015 Ozone Transport = total allowable 

NOX emissions from all cement kilns 

located at one cement plant, in tons per 

day, on a 30-operating day rolling 

average basis; 

KD = 1.7 pounds NOX per ton of clinker for 

dry preheater-precalciner or precalciner 

kilns; 

KW = 3.4 pounds NOX per ton of clinker for 

long wet kilns; 

ND = the average annual production in tons 

of clinker plus one standard deviation 

for the three most recent calendar years 

from all dry preheater-precalciner or 

precalciner kilns located at one cement 

plant; and 

NW = the average annual production in tons 

of clinker plus one standard deviation 

for the 3 most recent calendar years from 

all long wet kilns located at one cement 

plant. 

An affected cement plant will need to 

comply with both the source cap limit 

and the specific NOX emissions limits 

assigned to its individual kiln type(s). 

Refer to Section VII.C.2 of this proposed 

rule for additional information 

concerning the application of the source 

cap limit to this industry source group. 

TABLE I.B–4—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR IRON AND STEEL AND FERROALLOY EMISSIONS

UNITS

Emissions unit Proposed NOX emissions standard or requirement 

(lbs/hour or lb/mmBtu) 

Blast Furnace ........................................................................................... 0.03 lb/mmBtu. 

Basic Oxygen Furnace ............................................................................. 0.07 lb/ton. 

Electric Arc Furnace ................................................................................. 0.15 lb/ton steel. 

Ladle/tundish Preheaters .......................................................................... 0.06 lb/mmBtu. 

Reheat furnace ......................................................................................... 0.05 lb/mmBtu. 

Annealing Furnace ................................................................................... 0.06 lb/mmBtu. 

Vacuum Degasser .................................................................................... 0.03 lb/mmBtu. 

Ladle Metallurgy Furnace ......................................................................... 0.1 lb/ton. 

Taconite production kilns .......................................................................... Work practice standard to install low NOX technology/burners, test and 

set. 

Coke ovens (charging and coking) .......................................................... 0.6 lb/ton of coal charged. 

Coke ovens (pushing) .............................................................................. 0.015 lb/ton of coal pushed. 

Boilers—Coal ............................................................................................ 0.20 lb/mmBtu. 

Boilers—Residual oil ................................................................................ 0.20 lb/mmBtu. 

Boilers—Distillate oil ................................................................................. 0.12 lb/mmBtu. 

Boilers—Natural gas ................................................................................. 0.08 lb/mmBtu. 


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CAP2015 Ozone Transport= (KW x NW)+ (KD x ND) 

(2000 pounds x 365 days) ton year 
Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20047 

TABLE IV.B–5—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR FURNACE UNIT TYPES IN GLASS AND GLASS

PRODUCT MANUFACTURING

Furnace type 

Proposed NOX

emissions limit 

(lb/ton of glass 

produced) 

Container Glass Manufacturing Furnace ..................................................................................................................................... 4.0 

Pressed/Blown Glass Manufacturing Furnace or Fiberglass Manufacturing Furnace ................................................................ 4.0 

Flat Glass Manufacturing Furnace .............................................................................................................................................. 9.2 

TABLE I.B–6—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR

HIGH-EMITTING EQUIPMENT AND

LARGE BOILERS IN BASIC CHEMICAL

MANUFACTURING, PETROLEUM AND

COAL PRODUCTS MANUFACTURING, 

AND PULP, PAPER, AND PAPERBOARD MILLS

Unit type 

Emissions limit 

(lbs NOX/ 

mmBtu) 

Coal ...................................... 0.20 

Residual oil ........................... 0.20 

Distillate oil ........................... 0.12 

Natural gas ........................... 0.08 

Refer to Section VII.C of this proposed 

rule for applicability criteria, 

compliance assurance requirements, 

and the EPA’s rationale in proposing 

these emissions limits for each of the 

non-EGU industries covered by the 

proposed rule. In addition, the EPA 

requests comment on several topics 

regarding the implementation of 

emissions limits for non-EGU sources 

that are proposed in this rulemaking, 

including controls on emissions units 

and control installation timing. See 

Section VI.D.2.a of this proposed rule 

for a list of detailed questions on which 

the Agency is soliciting public 

comment. 

The remainder of this preamble is 

organized as follows: Section III of this 

proposed rule outlines general 

applicability criteria for the proposed 

rule and describes the EPA’s legal 

authority for this proposed rule, the 

relationship of the proposed rule to 

previous interstate ozone transport 

rulemakings, and the incremental costs 

and benefits of the proposed rule; 

Section IV of this proposed rule 

describes the human health and 

environmental challenges posed by 

interstate transport contributions to 

ozone air quality problems, as well as 

EPA’s overall approach for addressing 

interstate transport for the 2015 ozone 

NAAQS in this proposed rule; Section 

V of this proposed rule describes the 

Agency’s analyses of air quality data to 

inform this proposed rulemaking, 

including descriptions of the air quality 

modeling platform and emissions 

inventories used in the proposed rule, 

as well as EPA’s methods for identifying 

downwind air quality problems and 

upwind states’ ozone transport 

contributions to downwind states; 

Section VI of this proposed rule 

describes EPA’s approach to quantifying 

upwind states’ obligations in the form of 

EGU NOX control stringencies and nonEGU emissions limits; Section VII of 

this proposed rule describes key 

elements of the implementation 

schedule for EGU and non-EGU 

emissions reductions requirements, 

including details regarding the revised 

aspects of the CSAPR NOX Group 3 

trading program and compliance 

deadlines, as well as regulatory 

requirements and compliance deadlines 

for non-EGU sources; Section VIII of this 

proposed rule discusses the 

environmental justice considerations of 

the proposed rule; Section IX of this 

proposed rule describes the expected 

costs, benefits, and other impacts of this 

proposed rule; Section X of this 

proposed rule provides a summary of 

proposed changes to the existing 

regulatory text; and Section XI of this 

proposed rule discusses the statutory 

and executive orders affecting this 

proposed rulemaking. 

C. Costs and Benefits 

A summary of the key results of the 

cost-benefit analysis that was prepared 

for this proposed rule is presented in 

Table I.C–1. Table I.C–1 presents 

estimates of the present values (PV) and 

equivalent annualized values (EAV), 

calculated using discount rates of 3 and 

7 percent as directed by OMB’s Circular 

A–4, of the health benefits, compliance 

costs, and net benefits of the proposed 

rule, in 2016 dollars, discounted to 

2022. The estimated monetized net 

benefits are the estimated monetized 

benefits minus the estimated monetized 

costs of the proposed rule. These results 

present an incomplete overview of the 

effects of the proposal, because 

important categories of benefits— 

including benefits from reducing 

climate pollution, other types of air 

pollutants, and water pollution—were 

not monetized and are therefore not 

reflected in the cost-benefit tables. We 

anticipate that taking non-monetized 

effects into account would show the 

proposal to be more net beneficial than 

this table reflects. 

TABLE I.C–1—ESTIMATED MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS OF THE PROPOSED RULE, 

2023 THROUGH 2042 

[Millions 2016$, discounted to 2022] a

3% Discount rate 7% Discount rate 

Present Value: 

Benefits b ........................................................................................................................................... 250,000 150,000 

Compliance Costs c .......................................................................................................................... 22,000 14,000 

Net Benefits ............................................................................................................................... 220,000 130,000 

Equivalent Annualized Value: 

Benefits ............................................................................................................................................. 17,000 14,000 

Compliance Costs ............................................................................................................................ 1,500 1,300 


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20048 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

TABLE I.C–1—ESTIMATED MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS OF THE PROPOSED RULE, 

2023 THROUGH 2042—Continued 

[Millions 2016$, discounted to 2022] a

3% Discount rate 7% Discount rate 

Net Benefits .................................................................................................................... 15,000 12,000 

a Rows may not appear to add correctly due to rounding. 

bThe annualized present value of costs and benefits are calculated over a 20-year period from 2023 to 2042. Monetized benefits include those 

related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. Several categories of benefits remain unmonetized and are thus not reflected 

in the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The U.S. District Court for the Western 

District of Louisiana has issued an injunction concerning the monetization of the benefits of greenhouse gas emission reductions by EPA and 

other defendants. See Louisiana v. Biden, No. 21–cv–01074–JDC–KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the 

benefit-cost analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for more discussion. In 

addition, there are important unquantified water quality benefits and benefits associated with reductions in other air pollutants. cThe costs presented in this table are consistent with the costs presented in Chapter 4 of the RIA. To estimate these annualized costs, EPA 

uses a conventional and widely accepted approach that applies a capital recovery factor (CRF) multiplier to capital investments and adds that to 

the annual incremental operating expenses. Costs were calculated using a 3.76% real discount rate consistent with the rate used in IPM’s objective function for cost-minimization. 

As shown in Table I.C–1, the PV of 

the benefits, associated with reductions 

in PM2.5 and ozone concentrations, of 

this proposed rule, discounted at a 3- 

percent discount rate, is estimated to be 

about $250,000 million, with an EAV of 

about $17,000 million. At a 7-percent 

discount rate, the PV of the benefits is 

estimated to be $150,000 million, with 

an EAV of about $14,000 million. The 

PV of the compliance costs, discounted 

at a 3-percent rate, is estimated to be 

about $22,000 million, with an EAV of 

about $1,500 million. At a 7-percent 

discount rate, the PV of the compliance 

costs is estimated to be about $14,000 

million, with an EAV of about $1,300 

million. 

II. Public Participation 

A. Written Comments 

Submit your comments, identified by 

Docket ID No. EPA–HQ–OAR–2021– 

0668 at https://www.regulations.gov 

(our preferred method), or the other 

methods identified in the ADDRESSES

section. Once submitted, comments 

cannot be edited or removed from the 

docket. The EPA may publish any 

comment received to its public docket. 

Do not submit to EPA’s docket at 

https://www.regulations.gov any 

information you consider to be 

Confidential Business Information (CBI) 

or other information whose disclosure is 

restricted by statute. Multimedia 

submissions (audio, video, etc.) must be 

accompanied by a written comment. 

The written comment is considered the 

official comment and should include 

discussion of all points you wish to 

make. The EPA will generally not 

consider comments or comment 

contents located outside of the primary 

submission (i.e., on the web, cloud, or 

other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

https://www.epa.gov/dockets/ 

commenting-epa-dockets. 

Due to public health concerns related 

to COVID–19, the EPA Docket Center 

and Reading Room are open to the 

public by appointment only. Our Docket 

Center staff also continues to provide 

remote customer service via email, 

phone, and webform. Hand deliveries or 

couriers will be received by scheduled 

appointment only. For further 

information and updates on EPA Docket 

Center services, please visit us online at 

https://www.epa.gov/dockets. 

The EPA continues to carefully and 

continuously monitor information from 

the Centers for Disease Control and 

Prevention (CDC), local area health 

departments, and our Federal partners 

so that we can respond rapidly as 

conditions change regarding COVID–19. 

B. Submitting Confidential Business 

Information 

Do not submit information containing 

CBI to the EPA through https://

www.regulations.gov. Clearly mark the 

part or all of the information that you 

claim to be CBI. For CBI information on 

any digital storage media that you mail 

to the EPA, mark the outside of the 

digital storage media as CBI and then 

identify electronically within the digital 

storage media the specific information 

that is claimed as CBI. In addition to 

one complete version of the comments 

that includes information claimed as 

CBI, you must submit a copy of the 

comments that does not contain the 

information claimed as CBI directly to 

the public docket through the 

procedures outlined in Instructions 

earlier. If you submit any digital storage 

media that does not contain CBI, mark 

the outside of the digital storage media 

clearly that it does not contain CBI. 

Information not marked as CBI will be 

included in the public docket and the 

EPA’s electronic public docket without 

prior notice. Information marked as CBI 

will not be disclosed except in 

accordance with procedures set forth in 

40 Code of Federal Regulations (CFR) 

part 2. Our preferred method to receive 

CBI is for it to be transmitted to 

electronically using email attachments, 

File Transfer Protocol (FTP), or other 

online file sharing services (e.g., 

Dropbox, OneDrive, Google Drive). 

Electronic submissions must be 

transmitted directly to the OAQPS CBI 

Office using the email address, 

oaqpscbi@epa.gov, and should include 

clear CBI markings as described above. 

If assistance is needed with submitting 

large electronic files that exceed the file 

size limit for email attachments, and if 

you do not have your own file sharing 

service, please email oaqpscbi@epa.gov 

to request a file transfer link. If sending 

CBI information through the postal 

service, please send it to the following 

address: OAQPS Document Control 

Officer (C404–02), OAQPS, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention Docket ID No. EPA– 

HQ–OAR–2021–0668. The mailed CBI 

material should be double wrapped and 

clearly marked. Any CBI markings 

should not show through the outer 

envelope. 

C. Participation in Virtual Public 

Hearing 

Please note that because of current 

CDC recommendations, as well as state 

and local orders for social distancing to 

limit the spread of COVID–19, the EPA 

cannot hold in-person public meetings 

at this time. 

The EPA will begin pre-registering 

speakers for the hearing no later than 1 

business day after publication of this 

document in the Federal Register. To 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20049 

register to speak at the virtual hearing, 

please use the online registration form 

available at https://www.epa.gov/csapr/ 

csapr-2015-ozone-naaqs. The last day to 

pre-register to speak at the hearing will 

be April 21, 2022. The EPA will post a 

general agenda for the hearing that will 

list pre-registered speakers in 

approximate order at: https://

www.epa.gov/csapr/csapr-2015-ozonenaaqs. 

The virtual public hearing will be 

held on via teleconference on April 21, 

2022. The virtual public hearing will 

convene at 10:00 a.m. Eastern Time (ET) 

and will conclude at 7:00 p.m. ET. The 

EPA may close a session 15 minutes 

after the last pre-registered speaker has 

testified if there are no additional 

speakers. For information or questions 

about the public hearing, please contact 

Ms. Holly DeJong at Dejong.holly@

epa.gov. The EPA will announce further 

details at https://www.epa.gov/csapr/ 

csapr-2015-ozone-naaqs. 

The EPA will make every effort to 

follow the schedule as closely as 

possible on the day of the hearing; 

however, please plan for the hearings to 

run either ahead of schedule or behind 

schedule. 

Each commenter will have 5 minutes 

to provide oral testimony. The EPA 

encourages commenters to provide the 

EPA with a copy of their oral testimony 

electronically (via email) by emailing it 

to Dejong.holly@epa.gov. The EPA also 

recommends submitting the text of your 

oral comments as written comments to 

the rulemaking docket. 

The EPA may ask clarifying questions 

during the oral presentations, but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral comments 

and supporting information presented at 

the public hearing. 

Please note that any updates made to 

any aspect of the hearing will be posted 

online at https://www.epa.gov/csapr/ 

csapr-2015-ozone-naaqs. While the EPA 

expects the hearing to go forward as set 

forth above, please monitor our website 

or contact Ms. Holly DeJong at 

Dejong.holly@epa.gov to determine if 

there are any updates. The EPA does not 

intend to publish a document in the 

Federal Register announcing updates. 

If you require the services of a 

translator or special accommodations 

such as audio description, please preregister for the hearing and describe 

your needs by April 18, 2022. EPA may 

not be able to arrange accommodations 

without advanced notice. 

III. General Information 

A. Does this action apply to me? 

This proposed rule affects EGU and 

non-EGU sources, and regulates the 

groups identified in Table III.A–1. 

TABLE III.A–1—REGULATED GROUPS

Industry group NAICS 

Fossil fuel-fired electric power generation ......................................... 221112 

Pipeline Transportation of Natural 

Gas .............................................. 4862 

Cement and Concrete Product 

Manufacturing ............................. 3273 

Iron and Steel Mills and Ferroalloy 

Manufacturing ............................. 3311 

Glass and Glass Product Manufacturing ........................................... 3272 

Basic Chemical Manufacturing ....... 3251 

Petroleum and Coal Products Manufacturing .................................... 3241 

Pulp, Paper, and Paperboard Mills 3221 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this proposed rule. This 

table lists the types of entities that the 

EPA is now aware could potentially be 

regulated by this proposed rule. Other 

types of entities not listed in the table 

could also be regulated. For example, 

the EPA is requesting comment in 

Section VI.B.3 of this proposed rule on 

potential control strategies for sources 

outside of the categories listed in the 

Table III.A.1, such as municipal waste 

combustors (MWCs). To determine 

whether your EGU entity is proposed to 

be regulated by this proposed rule, you 

should carefully examine the 

applicability criteria found in 40 CFR 

97.1004, which the EPA is not 

proposing to alter in this proposed rule. 

If you have questions regarding the 

applicability of this proposed rule to a 

particular entity, consult the person 

listed in the FOR FURTHER INFORMATION

CONTACT section. 

B. What action is the Agency taking? 

The EPA evaluated whether interstate 

ozone transport emissions from upwind 

states are significantly contributing to 

nonattainment, or interfering with 

maintenance, of the 2015 ozone NAAQS 

in any downwind state using the same 

4-step interstate transport framework 

that was developed in previous ozone 

transport rulemakings. The EPA is 

proposing to find that emissions 

reductions are required from EGU and 

non-EGU sources in a total of 26 

upwind states to eliminate significant 

contribution to downwind air quality 

problems for the 2015 ozone standard 

under the interstate transport provision 

of the CAA. The EPA will ensure that 

these NOX emissions reductions are 

achieved by issuing proposed FIP 

requirements for 26 states: Alabama, 

Arkansas, California, Delaware, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Pennsylvania, Tennessee, Texas, Utah, 

Virginia, West Virginia, Wisconsin, and 

Wyoming. 

The EPA is proposing to revise the 

existing CSAPR Group 3 Trading 

Program to include additional states 

beginning in the 2023 ozone season. 

EGUs in five states not currently 

covered by any CSAPR trading program 

for seasonal NOX emissions—Delaware, 

Minnesota, Nevada, Utah, and 

Wyoming—would be added to the 

CSAPR Group 3 Trading Program under 

this proposed rule. EGUs in twelve 

states currently participating in the 

Group 3 Trading Program would remain 

in the program under this proposed 

rule: Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, New 

Jersey, New York, Ohio, Pennsylvania, 

Virginia, and West Virginia. EGUs in 

eight states (Alabama, Arkansas, 

Mississippi, Missouri, Oklahoma, 

Tennessee, Texas, and Wisconsin) will 

transition from the CSAPR Group 2 

Trading Program to the CSAPR Group 3 

Trading Program under this proposed 

rule beginning in the 2023 ozone 

season. The EPA proposes to establish 

control stringency levels reflecting 

installation of state-of-the-art 

combustion controls on certain covered 

EGU sources in emissions budgets 

beginning in the 2024 ozone season. The 

EPA proposes to establish control 

stringency levels reflecting installation 

of new SCR or SNCR controls on certain 

covered EGU sources in emissions 

budgets beginning in the 2026 ozone 

season. 

As a complement to the ozone season 

emissions budgets, the EPA is also 

proposing to establish backstop daily 

emissions rates of 0.14 lb/mmBtu for 

coal-fired steam units greater than or 

equal to 100 MW in covered states. The 

backstop emissions rates will first apply 

in 2024 for coal-fired steam sources 

with existing SCRs, and in 2027 for 

those currently without SCRs. 

In this proposed rule, the EPA is 

proposing to require emissions 

limitations for non-EGU sources in 23 

states: Arkansas, California, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Pennsylvania, Texas, Utah, Virginia, 

West Virginia, Wisconsin, and 


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18 42 U.S.C. 7410(a)(1). 

19See EPA v. EME Homer City Generation, L.P., 

572 U.S. 489, 509–10 (2014). 

20 42 U.S.C. 7410(a)(2). 

21EPA’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). 

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

23 42 U.S.C. 7410(a)(2)(D)(i)(I). 

24 Id. 

25 42 U.S.C. 7407(d). 

26 42 U.S.C. 7511, 7511a. 

27 42 U.S.C. 7511a. 

28 42 U.S.C. 7511(b). 

29 42 U.S.C. 7601(a)(1). 

30 42 U.S.C. 7410(k)(6). 

31 42 U.S.C. 7601(d)(4). 

Wyoming. In these states, EPA is 

proposing to require emissions 

limitations for the following unit types 

in non-EGU industries: Furnaces in 

Glass and Glass Product Manufacturing; 

boilers and furnaces in Iron and Steel 

Mills and Ferroalloy Manufacturing; 

kilns in Cement and Cement Product 

Manufacturing; reciprocating internal 

combustion engines in Pipeline 

Transportation of Natural Gas; and highemitting equipment and large boilers in 

Basic Chemical Manufacturing, 

Petroleum and Coal Products 

Manufacturing, and Pulp, Paper, and 

Paperboard Mill. See Table III.A–1 for a 

list of NAICS codes for each entity 

included for regulation under this 

proposed rule. 

The proposed rule would reduce the 

transport of ozone precursor emissions 

to downwind areas, which is protective 

of human health and the environment 

because acute and chronic exposure to 

ozone are both associated with negative 

health impacts. Ozone exposure is also 

associated with negative effects on 

ecosystems. Additional information on 

the human health and environmental 

benefits from the air quality issues 

addressed by this proposed rule are 

included in Section IV of this proposed 

rule. 

C. What is the Agency’s legal authority 

for taking this action? 

1. Statutory Authority 

The statutory authority for this 

proposed rule is provided by the CAA 

as amended (42 U.S.C. 7401 et seq.). 

Specifically, sections 110 and 301 of the 

CAA provide the primary statutory 

underpinnings for this proposed rule. 

The most relevant portions of CAA 

section 110 are subsections 110(a)(1), 

110(a)(2) (including 110(a)(2)(D)(i)(I)), 

110(c)(1), and 110(k)(6)). 

CAA section 110(a)(1) provides that 

states must make SIP submissions 

‘‘within 3 years (or such shorter period 

as the Administrator may prescribe) 

after the promulgation of a national 

primary ambient air quality standard (or 

any revision thereof),’’ and that these 

SIP submissions are to provide for the 

‘‘implementation, maintenance, and 

enforcement’’ of such NAAQS.18 The 

statute directly imposes on states the 

duty to make these SIP submissions, 

and the requirement to make the 

submissions is not conditioned upon 

the EPA taking any action other than 

promulgating a new or revised 

NAAQS.19

The EPA has historically referred to 

SIP submissions made for the purpose 

of satisfying the applicable requirements 

of CAA sections 110(a)(1) and 110(a)(2) 

as ‘‘infrastructure SIP’’ or ‘‘iSIP’’ 

submissions. CAA section 110(a)(1) 

addresses the timing and general 

requirements for iSIP submissions, and 

CAA section 110(a)(2) provides more 

details concerning the required content 

of these submissions.20 It includes a list 

of specific elements that ‘‘[e]ach such 

plan’’ must address.21

CAA section 110(c)(1) requires the 

Administrator to promulgate a FIP at 

any time within two years after the 

Administrator: (1) Finds that a state has 

failed to make a required SIP 

submission; (2) finds a SIP submission 

to be incomplete pursuant to CAA 

section 110(k)(1)(C); or (3) disapproves 

a SIP submission. This obligation 

applies unless the state corrects the 

deficiency through a SIP revision that 

the Administrator approves before the 

FIP is promulgated.22

CAA section 110(a)(2)(D)(i)(I), also 

known as the ‘‘good neighbor’’ 

provision, provides the primary basis 

for this proposed rule.23 It requires that 

each state SIP include provisions 

sufficient to ‘‘prohibit[ ], consistent with 

the provisions of this subchapter, any 

source or other type of emissions 

activity within the State from emitting 

any air pollutant in amounts which 

will—(I) contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other State with 

respect to any [NAAQS].’’ 24 The EPA 

often refers to the emissions reduction 

requirements under this provision as 

‘‘good neighbor obligations’’ and 

submissions addressing these 

requirements as ‘‘good neighbor SIPs.’’ 

Once EPA promulgates a NAAQS, the 

EPA must designate areas as being in 

‘‘attainment’’ or ‘‘nonattainment’’ of the 

NAAQS, or ‘‘unclassifiable.’’ CAA 

section 107(d).25 For ozone, 

nonattainment is further split into five 

classifications based on the severity of 

the violation—Marginal, Moderate, 

Serious, Severe, or Extreme. Higher 

classifications provide states with 

progressively more time to attain while 

imposing progressively more stringent 

control requirements. See CAA sections 

181, 182.26 In general, states with 

nonattainment areas classified as 

Moderate or higher must submit plans 

to EPA to bring these areas into 

attainment according to the statutory 

schedule. CAA section 182.27 If an area 

fails to attain the NAAQS by the 

attainment date associated with its 

classification, it is ‘‘bumped up’’ to the 

next classification. CAA section 

181(b).28

Section 301(a)(1) of the CAA gives the 

Administrator the general authority to 

prescribe such regulations as are 

necessary to carry out functions under 

the Act.29 Pursuant to this section, EPA 

has authority to clarify the applicability 

of CAA requirements and undertake 

other rulemaking action as necessary to 

implement CAA requirements. CAA 

section 301 affords the Agency any 

additional authority that may be needed 

in order to make certain other changes 

to its regulations under 40 CFR parts 52, 

75, 78, and 97, in order to effectuate the 

purposes of the Act. Such changes are 

discussed in Section X of this proposed 

rule. 

Section 110(k)(6) of the CAA gives the 

Administrator authority, without any 

further submission from a state, to 

revise certain prior actions, including 

actions to approve SIPs, upon 

determining that those actions were in 

error.30 The EPA proposes to make an 

error correction under CAA section 

110(k)(6) with respect to its prior 

approval of the 2015 ozone transport 

SIP submission from the State of 

Delaware. This is further discussed in 

Section IV.C.1 of the proposed rule. 

Tribes are not required to submit state 

implementation plans. However, as 

explained in EPA’s regulations outlining 

Tribal Clean Air Act authority, the EPA 

is authorized to promulgate FIPs for 

Indian country as necessary or 

appropriate to protect air quality if a 

tribe does not submit, and obtain EPA 

approval of, an implementation plan. 

See 40 CFR 49.11(a); see also CAA 

section 301(d)(4).31 In this proposed 

rule, the EPA proposes an ‘‘appropriate 

or necessary’’ finding under CAA 

section 301(d) and proposes tribal FIP(s) 

as necessary to implement the relevant 

requirements. This is further discussed 

in Section IV.C.2 of the proposed rule. 


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32 Finding of Significant Contribution and 

Rulemaking for Certain States in the Ozone 

Transport Assessment Group Region for Purposes of 

Reducing Regional Transport of Ozone, 63 FR 

57356 (Oct. 27, 1998). As originally promulgated, 

the NOX SIP Call also addressed good neighbor 

obligations under the 1997 8-hour ozone NAAQS, 

but EPA subsequently stayed and later rescinded 

the rule’s provisions with respect to that standard. 

See 84 FR 8422 (March 8, 2019). 

33 ‘‘Allowance Trading,’’ sometimes referred to as 

‘‘cap and trade,’’ is an approach to reducing 

pollution that has been used successfully to protect 

human health and the environment. The design 

elements of EPA’s most recent trading programs are 

discussed in Section VII.B.1.a of this proposed rule. 

34Rule To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Clean Air Interstate 

Rule); Revisions to Acid Rain Program; Revisions to 

the NOX SIP Call, 70 FR 25162 (May 12, 2005). 

35 70 FR 21147 (April 25, 2005). 36 71 FR 25328 (April 28, 2006). 

37 Federal Implementation Plans: Interstate 

Transport of Fine Particulate Matter and Ozone and 

Correction of SIP Approvals, 76 FR 48208, 48217 

(August 8, 2011). 

38 76 FR 48208. 

39CSAPR was revised by several rulemakings 

after its initial promulgation in order to revise 

certain states’ budgets and to promulgate FIPs for 

five additional states addressing the good neighbor 

obligation for the 1997 ozone NAAQS. See 76 FR 

80760 (December 27, 2011); 77 FR 10324 (February 

21, 2012); 77 FR 34830 (June 12, 2012). 

40On August 21, 2012, the D.C. Circuit issued a 

decision in EME Homer City Generation, L.P. v. 

EPA, 696 F.3d 7 (D.C. Cir. 2012), vacating CSAPR. 

The EPA sought review with the D.C. Circuit en 

banc and the D.C. Circuit declined to consider 

EPA’s appeal en banc. EME Homer City Generation, 

L.P. v. EPA, No. 11–1302 (D.C. Cir. January 24, 

2013), ECF No. 1417012 (denying EPA’s motion for 

rehearing en banc). 

41Cross-State Air Pollution Rule Update for the 

2008 Ozone NAAQS, 81 FR 74504, 74511 (October 

26, 2016). 

42 81 FR 74504. 

43One state, Kansas, was made newly subject to 

ozone season NOX requirements by the CSAPR 

Update. All other CSAPR Update states were 

already subject to ozone season NOX requirements 

under CSAPR. 

44 81 FR 74516. EPA’s final 2008 Ozone NAAQS 

SIP Requirements Rule, 80 FR 12264, 12268 (March 

6, 2015), revised the attainment deadline for ozone 

nonattainment areas designated as Moderate to July 

20, 2018. See 40 CFR 51.1103. In order to 

demonstrate attainment by this deadline, states 

were required to rely on design values calculated 

using ozone season data from 2015 through 2017, 

since the July 20, 2018, deadline did not afford 

enough time for measured data of the full 2018 

ozone season. 

D. What actions has EPA previously 

issued to address regional ozone 

transport? 

The EPA has issued several major 

rules interpreting and clarifying the 

requirements of CAA section 

110(a)(2)(D)(i)(I) with respect to the 

regional transport of ozone. These rules, 

and the associated court decisions 

addressing these rules, summarized 

here, provide important direction 

regarding the requirements of CAA 

section 110(a)(2)(D)(i)(I). 

The ‘‘NOX SIP Call,’’ promulgated in 

1998, addressed the good neighbor 

provision for the 1979 1-hour ozone 

NAAQS.32 The rule required 22 states 

and the District of Columbia to amend 

their SIPs to reduce NOX emissions that 

contribute to ozone nonattainment in 

downwind states. The EPA set ozone 

season NOX budgets for each state, and 

the states were given the option to 

participate in a regional allowance 

trading program, known as the NOX

Budget Trading Program.33 The D.C. 

Circuit largely upheld the NOX SIP Call 

in Michigan v. EPA, 213 F.3d 663 (D.C. 

Cir. 2000), cert. denied, 532 U.S. 904 

(2001). 

EPA’s next rule addressing the good 

neighbor provision, the Clean Air 

Interstate Rule (CAIR), was promulgated 

in 2005 and addressed both the 1997 

fine particulate matter (PM2.5) NAAQS 

and 1997 ozone NAAQS.34 CAIR 

required SIP revisions in 28 states and 

the District of Columbia to reduce 

emissions of sulfur dioxide (SO2) or 

NOX—important precursors of 

regionally transported PM2.5 (SO2 and 

annual NOX) and ozone (summer-time 

NOX). As in the NOX SIP Call, states 

were given the option to participate in 

regional trading programs to achieve the 

reductions. When the EPA promulgated 

the final CAIR in 2005, the EPA also 

issued findings that states nationwide 

had failed to submit SIPs to address the 

requirements of CAA section 

110(a)(2)(D)(i) with respect to the 1997 

PM2.5 and 1997 ozone NAAQS.35 On 

March 15, 2006, the EPA promulgated 

FIPs to implement the emissions 

reductions required by CAIR.36 CAIR 

was remanded to EPA by the D.C. 

Circuit in North Carolina v. EPA, 531 

F.3d 896 (D.C. Cir. 2008), modified on 

reh’g, 550 F.3d 1176. For more 

information on the legal issues 

underlying CAIR and the D.C. Circuit’s 

holding in North Carolina, refer to the 

preamble of the CSAPR rule.37

In 2011, the EPA promulgated CSAPR 

to address the issues raised by the 

remand of CAIR. CSAPR addressed the 

two NAAQS at issue in CAIR and 

additionally addressed the good 

neighbor provision for the 2006 PM2.5

NAAQS.38 CSAPR required 28 states to 

reduce SO2 emissions, annual NOX

emissions, or ozone season NOX

emissions that significantly contribute 

to other states’ nonattainment or 

interfere with other states’ abilities to 

maintain these air quality standards.39

To align implementation with the 

applicable attainment deadlines, the 

EPA promulgated FIPs for each of the 28 

states covered by CSAPR. The FIPs 

require EGUs in the covered states to 

participate in regional trading programs 

to achieve the necessary emissions 

reductions. Each state can submit a good 

neighbor SIP at any time that, if 

approved by EPA, would replace the 

CSAPR FIP for that state. 

CSAPR was the subject of an adverse 

decision by the D.C. Circuit in August 

2012.40 However, this decision was 

reversed in April 2014 by the Supreme 

Court, which largely upheld the rule, 

including EPA’s approach to addressing 

interstate transport in CSAPR. EPA v. 

EME Homer City Generation, L.P., 572 

U.S. 489 (2014) (EME Homer City I). The 

rule was remanded to the D.C. Circuit to 

consider claims not addressed by the 

Supreme Court. Id. In July 2015 the D.C. 

Circuit generally affirmed EPA’s 

interpretation of various statutory 

provisions and EPA’s technical 

decisions. EME Homer City Generation, 

L.P. v. EPA, 795 F.3d 118 (2015) (EME 

Homer City II). However, the court 

remanded the rule without vacatur for 

reconsideration of EPA’s emissions 

budgets for certain states, which the 

court found may have over-controlled 

those states’ emissions with respect to 

the downwind air quality problems to 

which the states were linked. Id. at 129– 

30, 138. For more information on the 

legal issues associated with CSAPR and 

the Supreme Court’s and D.C. Circuit’s 

decisions in the EME Homer City 

litigation, refer to the preamble of the 

CSAPR Update.41

In 2016, the EPA promulgated the 

CSAPR Update to address interstate 

transport of ozone pollution with 

respect to the 2008 ozone NAAQS.42

The final rule updated the CSAPR ozone 

season NOX emissions budgets for 22 

states to achieve cost-effective and 

immediately feasible NOX emissions 

reductions from EGUs within those 

states.43 The EPA aligned the analysis 

and implementation of the CSAPR 

Update with the 2017 ozone season in 

order to assist downwind states with 

timely attainment of the 2008 ozone 

NAAQS.44 The CSAPR Update 

implemented the budgets through FIPs 

requiring sources to participate in a 

revised CSAPR NOX ozone season 

trading program beginning with the 

2017 ozone season. As under CSAPR, 

each state could submit a good neighbor 

SIP at any time that, if approved by the 

EPA, would replace the CSAPR Update 

FIP for that state. The final CSAPR 

Update also addressed the remand by 

the D.C. Circuit of certain states’ CSAPR 

phase 2 ozone season NOX emissions 

budgets in EME Homer City II. 

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 


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20052 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

45 Determination Regarding Good Neighbor 

Obligations for the 2008 Ozone National Ambient 

Air Quality Standard, 83 FR 65878, 65882 (Dec. 21, 

2018). After promulgating the CSAPR Update and 

before promulgating the CSAPR Close-Out, the EPA 

approved a SIP from Kentucky resolving the 

Commonwealth’s good neighbor obligations for the 

2008 ozone NAAQS. 83 FR 33730 (July 17, 2018). 

In the Revised CSAPR Update, the EPA made an 

error correction under CAA section 110(k)(6) to 

convert this approval to a disapproval, because the 

Kentucky approval relied on the same analysis 

which the D.C. Circuit determined to be unlawful 

in the CSAPR Close-Out. 

46Subsequently, the D.C. Circuit made clear in a 

decision reviewing EPA’s denial of a petition under 

CAA section 126 that the holding in Wisconsin 

regarding alignment with downwind area’s 

attainment schedules applies with equal force to the 

Marginal area attainment date established under 

CAA section 181(a). See Maryland v. EPA, 958 F.3d 

1185, 1203–04 (D.C. Cir. 2020). 

47Revised Cross-State Air Pollution Rule Update 

for the 2008 Ozone NAAQS, 86 FR 23054 (April 30, 

2021). 

48The Revised CSAPR Update is currently subject 

to a petition for judicial review pending in the D.C. 

Circuit Court of Appeals, Midwest Ozone Group v. 

EPA, No. 21–1146 (D.C. Cir. June 25, 2021). 

49 80 FR 65291. 

50 40 CFR part 50, Appendix P to part 50 

51These 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. 

52Fann 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. 

53Christopher 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. 

2008 ozone NAAQS for 20 of the 22 

eastern states covered by the CSAPR 

Update, and reflected that 

determination in revisions to the 

existing state-specific sections of the 

CSAPR Update regulations for those 

states.45

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 CloseOut on the same grounds that it 

remanded the CSAPR Update in 

Wisconsin, specifically that the CloseOut rule did not address good neighbor 

obligations by ‘‘the next applicable 

attainment date’’ of downwind states. 

New York, 781 Fed. App’x at 7.46

In response to the Wisconsin remand 

of the CSAPR Update and the New York 

vacatur of the CSAPR Close-Out, the 

EPA promulgated the Revised CSAPR 

Update on April 30, 2021.47 The 

Revised CSAPR Update found that the 

CSAPR Update was a full remedy for 

nine of the covered states. For the 12 

remaining states, the EPA found that 

their projected 2021 ozone season NOX

emissions significantly contribute to 

downwind states’ nonattainment or 

maintenance problems. The EPA issued 

new or amended FIPs for these 12 states 

and required implementation of revised 

emissions budgets for EGUs beginning 

with the 2021 ozone season. Based on 

EPA’s assessment of remaining air 

quality issues and additional emissions 

control strategies for EGUs and 

emissions sources in other industry 

sectors (non-EGUs), the EPA determined 

that the NOX emissions reductions 

achieved by the Revised CSAPR Update 

fully eliminated these states’ significant 

contributions to downwind air quality 

problems for the 2008 ozone NAAQS. 

As under the CSAPR and the CSAPR 

Update, each state can submit a good 

neighbor SIP at any time that, if 

approved by EPA, would replace the 

Revised CSAPR Update FIP for that 

state.48

IV. Air Quality Issues Addressed and 

Overall Approach for the Proposed 

Rule 

A. The Interstate Ozone Transport Air 

Quality Challenge 

1. Nature of Ozone and the Ozone 

NAAQS 

Ground-level ozone is not emitted 

directly into the air but is created by 

chemical reactions between NOX and 

volatile organic compounds (VOCs) in 

the presence of sunlight. Emissions from 

electric utilities and industrial facilities, 

motor vehicles, gasoline vapors, and 

chemical solvents are some of the major 

sources of NOX and VOCs. 

Because ground-level ozone formation 

increases with temperature and 

sunlight, ozone levels are generally 

higher during the summer months. 

Increased temperature also increases 

emissions of volatile man-made and 

biogenic organics and can also 

indirectly increase NOX emissions (e.g., 

increased electricity generation for air 

conditioning). 

On October 1, 2015, the EPA 

strengthened the primary and secondary 

ozone standards to 70 ppb as an 8-hour 

level.49 Specifically, the standards 

require that the 3-year average of the 

fourth highest 24-hour maximum 8-hour 

average ozone concentration may not 

exceed 70 ppb as a truncated value (i.e., 

digits to right of decimal removed).50 In 

general, areas that exceed the ozone 

standard are designated as 

nonattainment areas, pursuant to the 

designations process under CAA section 

107, and are subject to heightened 

planning requirements depending on 

the degree of severity of their 

nonattainment classification, see CAA 

sections 181, 182. 

In the process of setting the 2015 

ozone NAAQS, the EPA noted that the 

conditions conducive to the formation 

of ozone (i.e., seasonally-dependent 

factors such as ambient temperature, 

strength of solar insolation, and length 

of day) differ by location, and that the 

Agency believes it is important that 

ozone monitors operate during all 

periods when there is a reasonable 

possibility of ambient levels 

approaching the level of the NAAQS. At 

that time, the EPA stated that ambient 

ozone concentrations in many areas 

could approach or exceed the level of 

the NAAQS, more frequently and during 

more months of the year compared with 

the historical ozone season monitoring 

lengths. Consequently, the EPA 

extended the ozone monitoring season 

for many locations. See 80 FR 65416 for 

more details. 

Furthermore, the EPA stated that in 

addition to being affected by changing 

emissions, future ozone concentrations 

may also be affected by climate change. 

Modeling studies in the EPA’s Interim 

Assessment (U.S. EPA, 2009a) that are 

cited in support of the 2009 

Endangerment Finding under CAA 

section 202(a) (74 FR 66496, Dec. 15, 

2009) as well as a recent assessment of 

potential climate change impacts (Fann 

et al., 2015) project that climate change 

may lead to future increases in summer 

ozone concentrations across the 

contiguous U.S.51 (80 FR 65300). The 

increase in ozone results from changes 

in local weather conditions, including 

temperature and atmospheric 

circulation patterns, as well as changes 

in ozone precursor emissions that are 

influenced by meteorology (Nolte et al., 

2018). While the projected impact may 

not be uniform, climate change has the 

potential to increase average 

summertime ozone relative to a future 

without climate change.52 53 54 Climate 


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54Nolte, 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. 

55Bergin, 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. 

56Butler, et al., ‘‘Response of Ozone and Nitrate 

to Stationary Source Reductions in the Eastern 

USA’’. Atmospheric Environment, 2011. 

57 ‘‘Ozone Air Pollution.’’ Introduction to 

Atmospheric Chemistry, by DANIEL J. JACOB, 

Princeton University Press, PRINCETON, NEW 

JERSEY, 1999, pp. 231–244. 

58 81 FR 74514. 

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). 

2. Ozone Transport 

Studies have established that ozone 

formation, atmospheric residence, and 

transport occur on a regional scale (i.e., 

thousands of kilometers) over much of 

the U.S.55 While substantial progress 

has been made in reducing ozone in 

many areas, the interstate transport of 

ozone precursor emissions remains an 

important contributor to peak ozone 

concentrations and high-ozone days 

during the summer ozone season. 

The EPA has previously concluded in 

the NOX SIP Call, CAIR, CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update that a regional NOX control 

strategy would be effective in reducing 

regional-scale transport of ozone 

precursor emissions. NOX emissions can 

be transported downwind as NOX or as 

ozone after transformation in the 

atmosphere. In any given location, 

ozone pollution levels are impacted by 

a combination of background ozone 

concentration, local emissions, and 

emissions from upwind sources 

resulting from ozone transport. 

Downwind states’ ability to meet healthbased air quality standards such as the 

NAAQS is challenged by the transport 

of ozone pollution across state borders. 

For example, ozone assessments 

conducted for the October 2015 

Regulatory Impact Analysis of the Final 

Revisions to the National Ambient Air 

Quality Standards for Ground-Level 

Ozone continue to show the importance 

of NOX emissions for ozone transport. 

This analysis is included in the docket 

for this proposal. 

Further, studies have found that EGU 

NOX emissions reductions can be 

effective in reducing individual 8-hour 

peak ozone concentrations and in 

reducing 8-hour peak ozone 

concentrations averaged across the 

ozone season. For example, a study that 

evaluates the effectiveness on ozone 

concentrations of EGU NOX reductions 

achieved under the NOX Budget Trading 

Program (i.e., the NOX SIP Call) shows 

that regulating NOX emissions in that 

program was highly effective in 

reducing ozone concentrations during 

the ozone season.56

Previous regional ozone transport 

efforts, including the NOX SIP Call, 

CAIR, CSAPR, the CSAPR Update, and 

the Revised CSAPR Update, required 

ozone season NOX reductions from EGU 

sources to address interstate transport of 

ozone. Together with NOX, EPA has also 

identified VOCs as a precursor in 

forming ground-level ozone. Ozone 

formation chemistry can be ‘‘NOXlimited,’’ where ozone production is 

primarily determined by the amount of 

NOX emissions or ‘‘VOC-limited,’’ 

where ozone production is primarily 

determined by the amount of VOC 

emissions.57 The EPA and others have 

long regarded NOX to be the more 

significant ozone precursor in the 

context of interstate ozone transport.58

The EPA has determined that the 

regulation of VOCs as an ozone 

precursor is not necessary to eliminate 

significant contribution of ozone 

transport to downwind areas in this 

proposed rule. As described in Section 

VI.A of this proposed rule, the EPA 

examined the results of the contribution 

modeling performed for this rule to 

identify the portion of the ozone 

contribution attributable to 

anthropogenic NOX emissions versus 

VOC emissions from each linked 

upwind state to each downwind 

receptor. Our analysis of the ozone 

contribution from upwind states subject 

to regulation under this proposed rule 

demonstrates that the vast majority of 

the downwind air quality areas are 

NOX-limited, rather than VOC-limited. 

Therefore, the proposed rule’s strategy 

for reducing regional-scale transport of 

ozone targets NOX emissions from 

stationary sources to achieve the most 

effective reductions of ozone transport 

over the geography of the affected 

downwind areas. 

Commenters on prior ozone transport 

rules have asserted that VOC emissions 

harm underserved and overburdened 

communities experiencing 

disproportionate environmental health 

burdens and facing other environmental 

injustices. The EPA acknowledges that 

VOCs can contain toxic chemicals that 

are detrimental to public health. The 

EPA conducted a demographic analysis 

as part of the regulatory impact analysis 

for the 2015 revisions to the primary 

and secondary ozone NAAQS. This 

analysis, which is included in the 

docket for this proposed rulemaking, 

found greater representation of minority 

populations in areas with poor air 

quality relative to the revised ozone 

standard than in the U.S. as a whole. 

The EPA concluded that populations in 

these areas would be expected to benefit 

from implementation of future air 

pollution control actions from state and 

local air agencies in implementing the 

strengthened standard. This proposed 

rule is an example of air pollution 

control actions implemented by the 

federal government in support of the 

more stringent 2015 ozone NAAQS, and 

populations living in downwind ozone 

nonattainment areas are expected to 

benefit from improved air quality that 

will result from reducing ozone 

transport. Further discussion of the 

environmental justice impacts of this 

proposed rule is located in Section VIII 

of this proposed rule and in the 

accompanying regulatory impact 

analysis, titled ‘‘Regulatory Impact 

Analysis for the Proposed Federal 

Implementation Plan Addressing 

Regional Ozone Transport for the 2015 

Ozone National Ambient Air Quality 

Standard’’ [EPA–452/D–22–001], which 

is available in the docket for this 

rulemaking. 

The Agency regulates exposure to 

toxic pollutant concentrations and 

ambient exposure to criteria pollutants 

other than ozone through other sections 

of the Act, such as the regulation of 

hazardous air pollutants under CAA 

section 112 or the process for revising 

and implementing the NAAQS under 

CAA sections 107–110. The purpose of 

the proposed rulemaking is to protect 

public health and the environment by 

eliminating significant contribution 

from 26 states to nonattainment or 

maintenance of the 2015 ozone NAAQS 

in order to meet the requirements of the 

CAA’s interstate transport provision. In 

this proposed rule, the EPA continues to 

observe that requiring NOX emissions 

reductions from stationary sources is an 

effective strategy for reducing regional 

ozone transport in the U.S. 

In Section VI of this proposed rule, 

EPA describes the multi-factor test that 

is used to determine NOX emissions 

reductions that are cost-effective and 

reduce interstate transport of groundlevel ozone. Our analysis indicates that 

the EGU and non-EGU control 

requirements proposed in this rule will 

provide meaningful improvements in air 

quality at the downwind receptors. 

Based on the implementation schedule 


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59Available at https://www.epa.gov/sites/default/ 

files/2016-02/documents/20151001ria.pdf. 

60See CSAPR, Final Rule, 76 FR 48208, 48248– 

48249 (August 8, 2011); CSAPR Update, Final Rule, 

81 FR 74504, 74517–74521 (October 26, 2016). 

61Specifically, the EPA analyzed 2021 to align 

with the attainment date for areas classified as 

Severe nonattainment for the 2008 ozone NAAQS, 

and because the last full ozone season before that 

date, in 2020, was already in the past. 

62 In CSAPR, the EPA did not use current 

monitored air quality conditions, because that data 

was influenced by the invalidated CAIR rule, which 

the EPA was replacing with CSAPR. See 81 FR 

74506, 74531. As the EPA is not replacing an 

existing transport program in this proposed rule, 

the Agency proposes to once again consider current 

monitored data as part of the process for identifying 

projected receptors for this rulemaking. 

63For ozone, the impacts include those from VOC 

and NOX from all sectors. 64The number of days used in calculating the 

average contribution metric has historically been 

determined in a manner that is generally consistent 

with EPA’s recommendations for projecting future 

year ozone design values. Our ozone attainment 

demonstration modeling guidance at the time of 

CSAPR recommended using all model-predicted 

days above the NAAQS to calculate future year 

design values (https://www3.epa.gov/ttn/scram/ 

guidance/guide/final-03-pm-rh-guidance.pdf). In 

2014, the EPA issued draft revised guidance that 

changed the recommended number of days to the 

top-10 model predicted days (https://

www3.epa.gov/ttn/scram/guidance/guide/Draft-O3- 

PM-RH-Modeling_Guidance-2014.pdf). For the 

CSAPR Update, the EPA transitioned to calculating 

design values based on this draft revised approach. 

The revised modeling guidance was finalized in 

2019 and, in this regard, EPA is calculating both the 

ozone design values and the contributions based on 

a top-10 day approach (https://www3.epa.gov/ttn/ 

scram/guidance/guide/O3-PM-RH-Modeling_

Guidance-2018.pdf). 

established in Section VII.A of this 

proposed rule, the EPA proposes to 

determine that the regulatory 

requirements included in the proposed 

rule are as expeditious as practicable 

and are aligned with the attainment 

schedule of downwind areas. 

3. Health and Environmental Effects 

Exposure to ambient ozone causes a 

variety of negative effects on human 

health, vegetation, and ecosystems. In 

humans, acute and chronic exposure to 

ozone is associated with premature 

mortality and a number of morbidity 

effects, such as asthma exacerbation. In 

ecosystems, ozone exposure causes 

visible foliar injury, decreases plant 

growth, and affects ecosystem 

community composition. See EPA’s 

October 2015 Regulatory Impact 

Analysis of the Final Revisions to the 

National Ambient Air Quality Standards 

for Ground-Level Ozone 59 in the docket 

for this proposal for more information 

on the human health and ecosystem 

effects associated with ambient ozone 

exposure. 

B. Proposed Rule Approach 

1. The 4-Step Interstate Transport 

Framework 

The EPA first developed a multi-step 

process to address the requirements of 

the good neighbor provision in the NOX

SIP Call and CAIR. The Agency built 

upon this framework and further refined 

the methodology for addressing 

interstate transport obligations in 

subsequent rules such as CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update.60 In CSAPR, the EPA first 

articulated a ‘‘4-step framework’’ within 

which to assess interstate transport 

obligations for ozone. In this proposed 

action to address interstate transport 

obligations for the 2015 ozone NAAQS, 

the EPA is again utilizing the 4-step 

interstate transport framework. These 

steps are: (1) Identifying downwind 

receptors that are expected to have 

problems attaining the NAAQS 

(nonattainment receptors) or 

maintaining the NAAQS (maintenance 

receptors); (2) determining which 

upwind states are ‘‘linked’’ to these 

identified downwind receptors based on 

a numerical contribution threshold; (3) 

for states linked to downwind air 

quality problems, identifying upwind 

emissions on a statewide basis that 

significantly contribute to downwind 

nonattainment or interfere with 

downwind maintenance of the NAAQS, 

considering cost- and air quality-based 

factors; and (4) for upwind states that 

are found to have emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in any 

downwind state, implementing the 

necessary emissions reductions through 

enforceable measures. 

a. Step 1 Approach 

The EPA proposes to continue to 

apply the method of the CSAPR Update 

and the Revised CSAPR Update for 

identifying nonattainment and 

maintenance receptors. In the Revised 

CSAPR Update, the EPA assessed 

downwind air quality problems using 

modeled future air quality 

concentrations for an analytic year 

aligned with the relevant attainment 

deadline for the NAAQS under 

consideration in that rulemaking.61

Similarly, in CSAPR, downwind air 

quality problems were assessed using 

modeled future air quality 

concentrations for a year aligned with 

attainment deadlines for the NAAQS 

considered in that rulemaking. The base 

case scenario provides an assessment of 

future air quality conditions that 

generally accounts for enforceable ‘‘onthe-books’’ emissions reductions and 

provides the most up-to-date forecast of 

what future emissions would resemble, 

in the absence of the transport policy in 

the proposed rule under evaluation. 

Downwind air quality problems are 

identified as the locations of monitoring 

sites that are projected to be unable to 

attain the NAAQS (‘‘nonattainment 

receptors’’) or as the locations of 

monitoring sites that are projected to be 

unable to maintain the NAAQS 

(‘‘maintenance receptors’’). In the 

CSAPR Update and the Revised CSAPR 

Update, unlike CSAPR,62 the EPA also 

considered currently available 

monitored air quality data to further 

inform the identification of projected 

downwind air quality problems. These 

same considerations are included for 

this proposal. Further details regarding 

the application of Step 1 of the 4-step 

interstate transport framework in this 

proposal are described in Section V.D of 

this proposed rule. 

b. Step 2 Approach 

The EPA proposes to apply the same 

approach for identifying which states 

are contributing to downwind 

nonattainment and maintenance 

receptors as it has applied in the three 

prior CSAPR rulemakings. CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update used a screening threshold of 1 

percent of the NAAQS to identify 

upwind states that were ‘‘linked’’ to 

downwind air pollution problems. 

States with contributions greater than or 

equal to the threshold for at least one 

downwind nonattainment or 

maintenance receptor identified in Step 

1 were identified as needing further 

evaluation of their good neighbor 

obligations to downwind states.63 The 

EPA evaluated each state’s contribution 

based on the average relative downwind 

impact calculated over multiple days.64

States whose air quality impacts to all 

downwind receptors were below this 

threshold did not require further 

evaluation for actions to address 

transport. In other words, the EPA 

determined that these states did not 

contribute to downwind air quality 

problems and therefore had no 

emissions reduction obligations under 

the good neighbor provision. The EPA 

applies a contribution screening 

threshold because many downwind 

ozone nonattainment areas receive 

transport contributions from a number 

of upwind states. While the proportion 

of contribution from a single upwind 

state may be relatively small, the effect 

of collective contribution resulting from 

multiple upwind states may 

substantially contribute to 

nonattainment of or interference with 

maintenance of the NAAQS in 

downwind areas. The preambles to the 


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65For simplicity, the EPA (and courts) at times 

will refer to the Step 3 analysis as determining 

‘‘significant contribution’’; however, EPA’s 

approach at Step 3 also implements the 

‘‘interference with maintenance’’ prong of the good 

neighbor provision, by also addressing emissions 

that impact the maintenance receptors identified at 

Step 1. See 86 FR 23074 (‘‘In effect, EPA’s 

determination of what level of upwind contribution 

constitutes ‘interference’ with a maintenance 

receptor is the same determination as what 

constitutes ‘significant contribution’ for a 

nonattainment receptor. Nonetheless, this continues 

to give independent effect to prong 2 because the 

EPA applies a broader definition for identifying 

maintenance receptors, which accounts for the 

possibility of problems maintaining the NAAQS 

under realistic potential future conditions.’’). 

66EPA v. EME Homer City Generation, L.P., 572 

U.S. 489 (2014). 

proposed and final CSAPR rules discuss 

the use of the 1 percent threshold for 

CSAPR. See 75 FR 45237 (August 2, 

2010); 76 FR 48238 (August 8, 2011). 

The same metric is discussed in the 

CSAPR Update, see 81 FR 74538, and in 

the Revised CSAPR Update, see 86 FR 

23054. In this proposed rule, the EPA 

updated the air quality modeling data 

used for determining contributions at 

Step 2 of the four-step interstate 

transport framework. The EPA 

otherwise continues to find that this 

threshold is appropriate to continue to 

apply for the 2015 ozone NAAQS. This 

proposal’s application of the Step 2 

approach is comprehensively described 

in Section V of this proposed rule. 

c. Step 3 Approach 

The EPA proposes to continue to 

apply the same approach as the prior 

three CSAPR rulemakings for evaluating 

‘‘significant contribution’’ at Step 3.65

For states that are linked in Step 3 to 

downwind air quality problems, 

CSAPR, the CSAPR Update, and the 

Revised CSAPR Update evaluated NOX

reduction potential, cost, and 

downwind air quality improvements 

available at various mitigation 

technology breakpoints (represented by 

cost thresholds) in the multi-factor test. 

In CSAPR, the CSAPR Update, and the 

Revised CSAPR Update, the EPA 

selected the technology breakpoint 

(represented by a cost threshold) that, in 

general, maximized cost-effectiveness— 

i.e., that achieved a reasonable balance 

of incremental NOX reduction potential 

and corresponding downwind ozone air 

quality improvements, relative to the 

other emissions budget levels evaluated. 

See, e.g., 81 FR 74550. The EPA 

determined the level of emissions 

reductions associated with that level of 

control stringency to constitute 

significant contribution to 

nonattainment or interfere with 

maintenance of a NAAQS downwind. 

See, e.g., 86 FR 23116. This approach 

was upheld by the U.S. Supreme Court 

in EPA v. EME Homer City.66

The EPA proposes in this action to 

apply this approach to identify EGU and 

non-EGU NOX control stringencies 

necessary to address significant 

contribution for the 2015 ozone 

NAAQS. The EPA applies a multifactor 

assessment using cost-thresholds, total 

emissions reduction potential, and 

downwind air quality effects as key 

factors in determining a reasonable 

balance of NOX controls in light of the 

downwind air quality problems. EPA’s 

evaluation of available NOX mitigation 

strategies for EGUs focuses on the same 

core set of measures as prior transport 

rules, and the EPA proposes a control 

stringency for EGUs from these 

measures that is commensurate with the 

nature of the ongoing ozone 

nonattainment and maintenance 

problems observed for the 2015 ozone 

NAAQS. Similarly, in this action, the 

EPA includes other industrial sources 

(non-EGUs) in its Step 3 analysis and 

proposes emissions limitations for 

certain non-EGU sources as needed to 

eliminate significant contribution and 

interference with maintenance. The 

available reductions and cost-levels for 

the non-EGU stringency is generally 

commensurate with the control strategy 

for EGUs. 

In CSAPR, the CSAPR Update, and 

the Revised CSAPR Update, EPA 

focused its Step 3 analysis on EGUs. In 

the Revised CSAPR Update, in response 

to the Wisconsin decision’s finding that 

the EPA had not adequately evaluated 

potential non-EGU reductions, see 938 

F.3d at 318, the EPA determined that 

the available NOX emissions reductions 

from non-EGU sources, for purposes of 

addressing good neighbor obligations for 

the 2008 ozone NAAQS, at a 

comparable cost threshold to the 

required EGU emissions reductions (for 

which EPA used an adjusted 

representative cost of $1,800 per ton), 

and based on the timing of when such 

measures could be implemented, did 

not provide a sufficiently meaningful 

and timely air quality improvement at 

the downwind receptors before those 

receptors were projected to resolve. See 

86 FR 23110. On that basis, the EPA 

made a finding that emissions 

reductions from non-EGU sources were 

not required to eliminate significant 

contribution to downwind air quality 

problems under the interstate transport 

provision for the 2008 ozone NAAQS. In 

this proposal, EPA’s ‘‘significant 

contribution’’ analysis at Step 3 of the 

4-step framework includes a 

comprehensive evaluation of major 

stationary source non-EGU industries in 

the linked upwind states. The EPA is 

proposing to find that emissions from 

certain non-EGU sources in the upwind 

states significantly contribute to 

downwind air quality problems for the 

2015 ozone NAAQS, and that costeffective emissions reductions from 

these sources are required to eliminate 

significant contribution under the 

interstate transport provision. Therefore, 

this proposed rule includes required 

emissions reductions from non-EGU 

sources in upwind states to fulfill 

interstate transport obligations for the 

2015 ozone NAAQS. This analysis is 

described fully in Section VI of the 

proposed rule. 

In this proposed rule, the EPA also 

continues to apply its approach for 

assessing and avoiding ‘‘over-control.’’ 

In EME Homer City, the Supreme Court 

held that ‘‘EPA cannot require a State to 

reduce its output of pollution by more 

than is necessary to achieve attainment 

in every downwind State or at odds 

with the one-percent threshold the 

Agency has set.’’ 572 U.S. at 521. The 

Court acknowledged that ‘‘instances of 

‘over-control’ in particular downwind 

locations may be incidental to 

reductions necessary to ensure 

attainment elsewhere.’’ Id. at 492. 

‘‘Because individual upwind States often 

‘contribute significantly’ to nonattainment in 

multiple downwind locations, the emissions 

reductions required to bring one linked 

downwind State into attainment may well be 

large enough to push other linked downwind 

States over the attainment line. As the Good 

Neighbor Provision seeks attainment in every 

downwind State, however, exceeding 

attainment in one State cannot rank as ‘overcontrol’ unless unnecessary to achieving 

attainment in any downwind State. Only 

reductions unnecessary to downwind 

attainment anywhere fall outside the 

Agency’s statutory authority.’’ 

Id. at 522 (footnotes excluded). 

The Court further explained that 

‘‘while EPA has a statutory duty to 

avoid over-control, the Agency also has 

a statutory obligation to avoid ‘undercontrol,’ i.e., to maximize achievement 

of attainment downwind.’’ Id. at 523. 

Therefore, in the CSAPR Update and 

Revised CSAPR Update, the EPA 

evaluated possible over-control by 

considering whether an upwind state is 

linked solely to downwind air quality 

problems that can be resolved at a lower 

cost threshold, or if upwind states 

would reduce their emissions at a lower 

cost threshold to the extent that they 

would no longer meet or exceed the 1 

percent air quality contribution 

threshold. See, e.g., 81 FR at 74551–52. 

See also Wisconsin, 938 F.3d at 325 


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67Section III of the Non-EGU Screening 

Assessment memorandum in the docket for this 

rulemaking describes EPA’s approach to evaluating 

impacts on downwind air quality, considering 

estimated total, maximum, and average 

contributions from each industry and the total 

number of receptors with contributions from each 

industry. 

(over-control must be proven through a 

‘‘ ‘particularized, as-applied 

challenge’ ’’) (quoting EME Homer City 

Generation, 572 U.S. at 523–24). The 

EPA continues to apply this framework 

for assessing over-control in this 

proposed rule, and, as discussed in 

Section VI.D.4 of this proposed rule, 

does not find any over-control at the 

proposed stringency to be sufficiently 

certain to warrant a relaxation in 

requirements for the sources in any 

covered state. 

This evaluation of cost, NOX

reductions, and air quality 

improvements, including consideration 

of whether there is proven over-control, 

results in EPA’s determination of the 

appropriate level of upwind control 

stringency that would result in 

elimination of emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in 

downwind areas. 

d. Step 4 Approach 

The EPA proposes an approach 

similar to its prior transport 

rulemakings to implement the necessary 

emissions reductions through 

permanent and enforceable measures. 

The EPA proposes to require EGU 

sources to participate in an emissions 

trading program and proposes 

additional enhancements to the trading 

regime to maintain the selected control 

stringency over time and improve 

emissions performance at individual 

units, offering a necessary measure of 

assurance that emissions controls will 

be operated throughout the ozone 

season. For non-EGUs, the EPA 

proposes permanent and enforceable 

emissions rate limits and work practice 

standards, and associated compliance 

requirements, on several types of NOXemitting combustion units across 

several industrial sectors. The measures 

for both EGUs and non-EGUs are 

proposed to be required throughout the 

May 1–September 30 ozone season 

annually. The EGU program will begin 

with the 2023 ozone season, and nonEGU implementation will begin with 

the 2026 ozone season. Refer to Section 

VII.A of this proposed rule for details on 

the implementation schedule. 

Based on the EPA’s experience in 

implementing prior transport 

rulemakings, the Agency is proposing 

several enhancements to its tradingprogram approach for implementing 

good neighbor requirements for EGUs. 

In CSAPR, the CSAPR Update, and the 

Revised CSAPR Update, the EPA 

established interstate trading programs 

for EGUs to implement the necessary 

emissions reductions. In each of these 

rules, EGUs in each covered state are 

assigned an emissions budget for their 

collective emissions. Emissions 

allowances are allocated to units 

covered by the trading program, and the 

covered units then surrender allowances 

after the close of each control period, 

usually in an amount equal to their 

ozone season EGU NOX emissions. 

While these programs have been 

effective in achieving overall reductions 

in emissions, experience has shown that 

these programs may not fully reflect in 

perpetuity the degree of emissions 

stringency determined necessary to 

eliminate significant contribution in 

Step 3 and may not adequately ensure 

the control of emissions throughout all 

days of the ozone season. At the same 

time, the EPA continues to find that an 

interstate-trading program approach 

delivers substantial benefits at Step 4 in 

terms of affording an appropriate degree 

of compliance flexibility, certainty in 

emissions outcomes, data and 

performance transparency, and costeffective achievement of a high degree 

of aggregate emissions reductions. As 

such, EPA proposes to retain an 

interstate trading program approach 

while proposing several enhancements 

to that approach. 

Thus, in this rulemaking, the EPA is 

proposing to include budget-setting 

procedures in the regulations that will 

allow state emissions budgets for 

control periods in 2025 and later years 

to reflect more current data on the 

composition and utilization of the EGU 

fleet (e.g., the 2025 budgets would 

reflect 2023 data, the 2026 budgets 

would reflect 2024 data, etc.). These 

enhancements would enable the trading 

program to better maintain over time the 

selected control stringency that was 

determined to be necessary to address 

states’ good neighbor obligations with 

respect to the 2015 ozone NAAQS. In 

prior programs, where state emissions 

budgets were static across years rather 

than calibrated to yearly fleet changes, 

the EPA has observed instances of units 

idling their emission controls in the 

latter years of the program. 

In the trading programs established 

for ozone season NOX emissions under 

CSAPR, the CSAPR Update, and the 

Revised CSAPR Update, the EPA 

included assurance provisions to limit 

state emissions to levels below 121 

percent of the state’s budget by 

requiring additional allowance 

surrenders in the instance that 

emissions in the state exceed this level. 

This limit on the degree to which a 

state’s emissions can exceed its budget 

is designed to allow for a certain level 

of year-to-year variability within power 

sector emissions to account for 

fluctuations in demand and EGU 

operations and is responsive to previous 

court decisions (see discussion in 

Section VII.B.4 of this proposed rule). In 

this action, the EPA again proposes to 

retain the existing assurance provisions 

that limit state emissions to levels below 

121 percent of the state’s budget by 

requiring additional allowance 

surrenders in the instance that 

emissions in the state exceed this level 

for the 2023 and 2024 control periods. 

For control periods in 2025 and later 

years, the EPA is proposing to maintain 

the same general approach, but with 

adjustments that account for actual 

operational conditions in each control 

period to determine the specific levels 

above which additional allowance 

surrenders would be required. In 

addition, EPA is also proposing several 

additional enhancements to the EGU 

trading program in this action, 

including routine recalibrations of the 

total amount of banked allowances, 

unit-specific backstop daily emissions 

rates for certain units, and unit-specific 

secondary emissions limitations for 

units that contribute to exceedances of 

the assurance levels, to ensure EGU 

emissions control operation and 

associated air quality improvements. 

Implementation of the proposed EGU 

emissions reductions using a CSAPR 

NOX trading program is further 

described in Section VII.B of this 

proposed rule. 

In this action, the EPA is also 

proposing to establish emissions 

limitations for the non-EGU industry 

sources listed in Table III.A–1. The EPA 

has the authority to require emissions 

limitations from stationary sources, as 

well as from other sources and 

emissions activities, under CAA section 

110(a)(2)(D)(i)(I). The EPA proposes that 

requiring NOX emissions reductions 

through emissions rate limits from 

certain non-EGU industry sources that 

the EPA found at Step 3 to be relatively 

impactful 67 on downwind air quality is 

an effective strategy for reducing 

regional ozone transport. Therefore, the 

EPA proposes NOX emissions 

limitations and associated compliance 

requirements for non-EGU sources to 

ensure the elimination of significant 

contribution of ozone precursor 

emissions required under the interstate 


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68National Ambient Air Quality Standards for 

Ozone, Final Rule, 80 FR 65292 (October 26, 2015). 

Although the level of the standard is specified in 

the units of ppm, ozone concentrations are also 

described in parts per billion (ppb). For example, 

0.070 ppm is equivalent to 70 ppb. 

69The EPA notes there are three consent decrees 

to resolve three deadline suits related to EPA’s duty 

to act on good neighbor SIP submissions for the 

2015 ozone NAAQS. In New York et al. v. Regan, 

et al. (No. 1:21–CV–00252, S.D.N.Y.), the EPA 

agreed to take final action on the 2015 ozone 

NAAQS good neighbor SIP submissions from 

Indiana, Kentucky, Michigan, Ohio, Texas, and 

West Virginia by April 30, 2022; however, if the 

EPA proposes to disapprove any SIP submissions 

and proposes a replacement FIP by February 28, 

2022, then EPA’s deadline to take final action on 

that SIP submission is extended to December 30, 

2022. In Downwinders at Risk et al. v. Regan (No. 

21–cv–03551, N.D. Cal.), the EPA agreed to take 

final action on the 2015 ozone NAAQS good 

neighbor SIP submissions from Alabama, Arkansas, 

Connecticut, Florida, Georgia, Illinois, Indiana, 

Iowa, Kansas, Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, New Jersey, New 

York, North Carolina, Ohio, Oklahoma, South 

Carolina, Tennessee, Texas, West Virginia, and 

Wisconsin by April 30, 2022; however, if the EPA 

proposes to disapprove any of these SIP 

submissions and proposes a replacement FIP by 

February 28, 2022, then EPA’s deadline to take final 

action on that SIP submission is December 30, 2022. 

In this CD, the EPA also agreed to take final action 

on Hawaii’s SIP submission by April 30, 2022, and 

to take final action on the SIP submissions of 

Arizona, California, Montana, Nevada, and 

Wyoming by December 15, 2022. In Our Children’s 

Earth Foundation v. EPA (No. 20–8232, S.D.N.Y.), 

the EPA agreed to take final action on the 2015 

ozone NAAQS good neighbor SIP submission from 

New York by April 30, 2022; however, if the EPA 

proposes to disapprove New York’s SIP submission 

and proposes a replacement FIP by February 28, 

2022, then EPA’s deadline to take final action on 

New York’s SIP submission is extended to 

December 30, 2022. 

70See EPA v. EME Homer City Generation, L.P., 

572 U.S. 489, 509 (2014) (citations omitted). 

71Wisconsin v. EPA, 938 F.3d 303, 313–14 (D.C. 

Cir. 2019) (citing North Carolina v. EPA, 531 F.3d 

896 (D.C. Cir. 2008). 

72 Maryland v. EPA, 958 F.3d 1185, 1203–04 (D.C. 

Cir. 2020). 

73See CAA section 181(a); 40 CFR 51.1303; 

Additional Air Quality Designations for the 2015 

Ozone National Ambient Air Quality Standards, 83 

FR 25776 (June 4, 2018, effective August 3, 2018). 

74 938 F.3d at 318 (‘‘When EPA determines a 

State’s SIP is inadequate, EPA presumably must 

issue a FIP that will bring that State into 

compliance before upcoming attainment deadlines, 

even if the outer limit of the statutory timeframe 

gives EPA more time to formulate the FIP.’’) (citing 

Sierra Club v. EPA, 294 F.3d 155, 161 (D.C. Cir. 

2002)). 

75See 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, 

Continued 

transport provision for the 2015 ozone 

NAAQS. 

Finally, the EPA proposes that the 

control measures determined to be 

required for the identified EGU and 

non-EGU sources apply to both existing 

units and any new, modified, or 

reconstructed units meeting the 

applicability criteria established in this 

proposal. This is consistent with EPA’s 

transport actions dating back to the NOX

SIP Call and the NOX Budget Trading 

Program. In all CSAPR EGU trading 

programs, for instance, new EGUs are 

subject to the program, and the EPA 

established provisions for the allocation 

of allowances to such units through 

‘‘new unit set asides.’’ See, e.g., 86 FR 

23126. In the NOX SIP Call, the EPA 

required that states cover new and 

existing units in the relevant source 

sectors through an enforceable cap or 

other emissions limitation. See 40 CFR 

51.121(f). EPA’s approach of including 

new units in the NOX Budget Trading 

Program promulgated under EPA’s CAA 

section 126 authority was upheld by the 

D.C. Circuit in Appalachian Power v. 

EPA, 249 F.3d 1032 (2001). The EPA 

explained in its action: 

Once EPA has determined that the 

emissions from the existing sources in an 

upwind State already make a significant 

contribution to one or more petitioning 

downwind States, any additional emissions 

from a new source in that upwind State 

would also constitute a portion of that 

significant contribution, unless the emissions 

from that new source are limited to the level 

of highly effective controls. 

Id. at 1058 (quoting EPA 1999 RTC at 

39). The court affirmed this approach: 

‘‘Indeed, it would be irrational to enable 

the EPA to make findings that a group 

of sources in an upwind state contribute 

to downwind nonattainment, but then 

preclude the EPA from regulating new 

sources that contribute to that same 

pollution.’’ Id. at 1057–58. The EPA 

proposes to adopt the same approach in 

this action, because this reasoning is 

equally applicable to addressing 

interstate transport obligations under 

CAA section 110(a)(2)(D)(i)(I) for the 

2015 ozone NAAQS. 

2. FIP Authority for Each State Covered 

by the Proposed Rule 

On October 1, 2015, the EPA 

promulgated a revision to the 2015 8- 

hour ozone NAAQS, lowering the level 

of both the primary and secondary 

standards to 0.070 parts per million 

(ppm).68 These revisions of the NAAQS, 

in turn, established a 3-year deadline for 

states to provide SIP submissions 

addressing infrastructure requirements 

under CAA sections 110(a)(1) and 

110(a)(2), including the good neighbor 

provision, by October 1, 2018. If the 

EPA makes a determination that a state 

failed to submit a SIP, or if EPA 

disapproves a SIP submission, then the 

EPA is obligated under CAA section 

110(c) to promulgate a FIP for that state 

within 2 years. For a more detailed 

discussion of CAA section 110 authority 

and timelines, refer to Section III.C of 

this proposed rule. 

The EPA is proposing this FIP action 

now to address twenty-six states’ good 

neighbor obligations for the 2015 ozone 

NAAQS, but the EPA will not finalize 

this FIP action for any state unless and 

until it has issued a final finding of 

failure to submit or a final disapproval 

of that state’s SIP submission. The EPA 

is not required to wait to propose a FIP 

until after the Agency proposes or 

finalizes a SIP disapproval or makes a 

finding of failure to submit.69 CAA 

section 110(c) authorizes EPA to 

promulgate a FIP ‘‘at any time within 2 

years’’ of a SIP disapproval or making a 

finding of failure to submit. Thus, the 

EPA may promulgate a FIP 

contemporaneously with or 

immediately following predicate final 

action on a SIP (or finding no SIP was 

submitted). In order to accomplish this, 

the EPA must necessarily be able to 

propose a FIP prior to taking final action 

to disapprove a SIP or make a finding 

of failure to submit. The Supreme Court 

recognized this in EME Homer City in 

holding that the EPA is not obligated to 

first define a state’s good neighbor 

obligations or give the state an 

additional opportunity to submit an 

approvable SIP before promulgating a 

FIP: ‘‘EPA is not obliged to wait two 

years or postpone its action even a 

single day: The Act empowers the 

Agency to promulgate a FIP ‘at any time’ 

within the two-year limit.’’ 70

Furthermore, the D.C. Circuit in 

Wisconsin held that states and EPA are 

obligated to fully address good neighbor 

obligations for ozone ‘‘as expeditiously 

as practical’’ and in no event later than 

the next relevant downwind attainment 

dates found in CAA section 181(a).71 In 

Maryland v. EPA, the D.C. Circuit made 

clear that Wisconsin’s and North 

Carolina’s holdings are fully applicable 

to the Marginal area attainment date for 

the 2015 ozone NAAQS,72 which fell on 

August 3, 2021.73 The Wisconsin court 

emphasized that EPA has the authority 

under CAA section 110 to structure and 

time its actions in a manner such that 

the Agency can ensure necessary 

reductions are achieved by the 

downwind attainment dates.74

On February 22, 2022, the EPA 

proposed to disapprove 19 good 

neighbor SIP submissions (Alabama, 

Arkansas, Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, 

Minnesota, Mississippi, Missouri, New 

Jersey, New York, Ohio, Oklahoma, 

Tennessee, Texas, West Virginia, 

Wisconsin).75 The EPA is proposing to 


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Ohio, Wisconsin). EPA has not yet proposed action 

on interstate transport SIPs submitted by California, 

Nevada, Utah, and Wyoming. 

76See the document titled ‘‘Status of CAA Section 

110(a)(2)(D)(i)(I) SIP Submissions for the 2015 

Ozone NAAQS for States Covered by the Proposed 

Federal Implementation Plan Addressing Regional 

Ozone Transport for the 2015 Ozone National 

Ambient Air Quality Standards,’’ included in the 

docket for this rulemaking, for additional 

information on EPA’s statutory authorities for this 

proposed rule. 

77 Findings of Failure To Submit a Clean Air Act 

Section 110 State Implementation Plan for 

Interstate Transport for the 2015 Ozone National 

Ambient Air Quality Standards (NAAQS), 84 FR 

66612 (December 5, 2019, effective January 6, 2020). 

78Air 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). 

79The EPA has not yet taken action on a 

subsequent good neighbor SIP submission from 

New Mexico or Utah; EPA is not including New 

Mexico in this proposed action. 

80Approval and Promulgation of Air Quality 

Implementation Plans; Delaware; Infrastructure 

Requirements for the 2015 Ozone Standard and 

Revisions to Modeling Requirements, 85 FR 25307 

(May 1, 2020). 

81 ‘‘Technical Support Document for the Delaware 

State Implementation Plan for the Infrastructure 

Requirements for the 2015 Ozone Standard and 

Revisions to Modeling Requirements’’ at 16, 

available in Docket No. EPA–R03–OAR–2019–0663. 

82 Id. at 17. Based on the 2023 modeling from the 

2018 memorandum, Delaware was expected in 2023 

to have a 0.40 ppb impact on a potential 

nonattainment receptor in Fairfield, Connecticut 

(Site ID 90019003) and a 0.38 ppb impact at a 

potential maintenance receptor in Queens, New 

York (Site ID 360810124). 

83The contribution from Delaware in 2023 to the 

receptor in Bristol, Pennsylvania, is 1.36 ppb. 

84See, e.g., 86 FR 23054, 23068 (error correcting 

prior approval of Kentucky’s transport SIP 

submission for the 2008 ozone NAAQS to a 

disapproval and simultaneously promulgating FIP 

on the basis of the Wisconsin and New York 

decisions remanding CSAPR Update and vacating 

CSAPR Close-Out and new information establishing 

Kentucky was linked to downwind receptors). 

promulgate 2015 ozone NAAQS good 

neighbor FIPs for these same states, as 

well as California, Nevada, and 

Wyoming, but will not finalize a FIP for 

any of these states unless and until the 

EPA formally finalizes disapprovals of 

their SIP submittals or, in the event that 

any of these states withdraw their good 

neighbor SIP submissions after this 

proposal, makes a finding of failure to 

submit.76 See CAA section 110(c). 

Additionally, the EPA has taken 

action that has triggered EPA’s 

obligation under CAA section 110(c) to 

promulgate FIPs addressing the good 

neighbor provision for some other 

states. On December 5, 2019, the EPA 

published a rule finding that seven 

states (Maine, New Mexico, 

Pennsylvania, Rhode Island, South 

Dakota, Utah, and Virginia) failed to 

submit or otherwise make complete 

submissions that address the 

requirements of CAA section 

110(a)(2)(D)(i)(I) for the 2015 ozone 

NAAQS.77 This finding triggered a 2- 

year deadline for the EPA to issue FIPs 

to address the good neighbor provision 

for these states by January 6, 2022. As 

the EPA has subsequently received and 

taken final action to approve good 

neighbor SIPs from Maine, Rhode 

Island, and South Dakota,78 the EPA 

currently has authority under the 

December 5, 2019, finding of failure to 

submit to issue FIPs for New Mexico, 

Pennsylvania, Utah, and Virginia. In 

this proposal, EPA is issuing proposed 

FIP requirements for Pennsylvania, 

Utah, and Virginia.79

C. Other CAA Authorities for This 

Action 

1. Correction of EPA’s Determination 

Regarding Delaware’s SIP Submission 

and Its Impact on EPA’s FIP Authority 

for Delaware 

In 2020, the EPA approved an 

infrastructure SIP submission from 

Delaware for the 2015 ozone NAAQS, 

which in part addressed the good 

neighbor provision at CAA section 

110(a)(2)(D)(i)(I).80 The EPA concluded 

that, based on the modeling results 

presented in a 2018 March 

memorandum and using a 2023 analytic 

year, Delaware’s largest impact on any 

potential downwind nonattainment or 

maintenance receptor was less than 1 

percent of the NAAQS.81 As a result, the 

EPA found that Delaware would not 

significantly contribute to 

nonattainment or interfere with 

maintenance in any other state.82

Therefore, the EPA approved the 

portion of Delaware’s infrastructure SIP 

that addressed CAA section 

110(a)(2)(D)(i)(I) for the 2015 ozone 

NAAQS. 

Subsequent to the release of the 

modeling data shared in the March 2018 

memorandum and EPA’s approval of 

Delaware’s 2015 ozone NAAQS good 

neighbor SIP submission, the EPA 

performed updated modeling, as 

described in Section V of this proposed 

rule. The data from this updated air 

quality modeling now show that 

Delaware is projected to contribute more 

than 1 percent of the NAAQS to 

downwind receptors in Bristol, 

Pennsylvania, in the 2023 analytic 

year.83 Therefore, in light of the 

modeling data, EPA is proposing to find 

that its approval of Delaware’s 2015 

ozone NAAQS infrastructure SIP 

submission, with regard only to the 

portion addressing the good neighbor 

provision at CAA section 

110(a)(2)(D)(i)(I), was in error. Section 

110(k)(6) of the CAA gives the 

Administrator authority, without any 

further submission from a state, to 

revise certain prior actions, including 

actions to approve SIPs, upon 

determining that those actions were in 

error.84 The modeling data demonstrate 

that EPA’s prior conclusion that 

Delaware will not significantly 

contribute to nonattainment or interfere 

with maintenance in any other state in 

the 2023 analytic year was incorrect, 

which means that EPA’s approval of 

Delaware’s good neighbor SIP 

submission was in error. 

Therefore, the EPA proposes to 

correct the error in Delaware’s good 

neighbor SIP approval. This error 

correction under CAA section 110(k)(6) 

would revise the approval of the portion 

of Delaware’s 2015 ozone NAAQS 

infrastructure SIP that addresses CAA 

section 110(a)(2)(D)(i)(I) to a disapproval 

and rescind any statements that the 

portion of Delaware’s infrastructure SIP 

submission that addresses CAA section 

110(a)(2)(D)(i)(I) satisfies the 

requirements of the good neighbor 

provision. The EPA is not proposing to 

correct the elements of Delaware’s 2015 

ozone NAAQS infrastructure SIP that do 

not address CAA section 

110(a)(2)(D)(i)(I). 

As discussed in greater detail in the 

sections that follow, the EPA is 

proposing to determine that there are 

additional emissions reductions that are 

required for Delaware to satisfy its good 

neighbor obligations for the 2015 ozone 

NAAQS. The analysis on which the EPA 

proposes this conclusion for Delaware is 

the same, regionally consistent 

analytical framework on which the 

Agency proposes FIP action for the 

other states included in this proposal. 

The Agency recognizes that it is 

possible, based on updated information 

for the final rule—as applied within a 

regionally consistent analytical 

framework—that Delaware (or other 

states for which the EPA proposes FIPs 

in this action) may be found to have no 

further interstate transport obligation for 

the 2015 ozone NAAQS. If such a 

circumstance were to occur, the EPA 

anticipates that it would not finalize 

this proposed error correction or may 

modify the error correction such that the 

approval of Delaware’s portion of the 

SIP as it relates to its good neighbor 

obligations may be affirmed. 


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85We note that, consistent with EPA’s prior good 

neighbor actions in California, the regulatory ozone 

monitor located on the Morongo Band of Mission 

Indians (‘‘Morongo’’) reservation is a projected 

downwind receptor in 2023. See monitoring site 

060651016 in Table V.D–1. We also note that the 

Temecula, California regulatory ozone monitor is a 

projected downwind receptor in 2023 and in past 

regulatory actions has been deemed representative 

of air quality on the Pechanga Band of Luisen ̃ o 

Indians (‘‘Pechanga’’) reservation. See, e.g., 

Approval of Tribal Implementation Plan and 

Designation of Air Quality Planning Area; Pechanga 

Band of Luisen ̃ o Mission Indians, 80 FR 18120, at 

18121–18123 (April 3, 2015); see also monitoring 

site 060650016 in Table V.D–1. The presence of 

receptors on, or representative of, the Morongo and 

Pechanga reservations does not trigger obligations 

for the Morongo and Pechanga Tribes. Nevertheless, 

these receptors are relevant to EPA’s assessment of 

any linked upwind states’ good neighbor 

obligations. See, e.g., Approval and Promulgation of 

Air Quality State Implementation Plans; California; 

Interstate Transport Requirements for Ozone, Fine 

Particulate Matter, and Sulfur Dioxide, 83 FR 65093 

(December 19, 2018). Under 40 CFR 49.4(a), tribes 

are not subject to the specific plan submittal and 

implementation deadlines for NAAQS-related 

requirements, including deadlines for submittal of 

plans addressing transport impacts. 

86See 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.’’). 

87With respect to any non-EGU sources located 

in the 301(d) FIP areas, the geographic scope of 

coverage of this proposed rule does not include 

those states for which EPA proposes to find, based 

on air quality modeling, that no further linkage 

exists by the 2026 analytic year at Steps 1 and 2. 

The states no longer projected to be linked in 2026 

are Alabama, Delaware, and Tennessee. 

88See Section VII.B.9 of this action for a 

discussion of revisions that are proposed in this 

rulemaking regarding the point in the allowance 

allocation process at which the EPA would 

establish set-asides of allowances for units in Indian 

country not subject to a state’s CAA implementation 

planning authority. 

2. Application of Rule in Indian Country 

and Necessary or Appropriate Finding 

The EPA proposes that this rule will 

be applicable in all areas of Indian 

country (as defined at 18 U.S.C. 1151) 

within the covered geography of the 

proposal, as defined below. Currently, 

certain areas of Indian country within 

the geography of the proposal are 

subject to state implementation 

planning authority. Other areas of 

Indian country within that geography 

would be subject to tribal planning 

authority, although none of the relevant 

tribes have as yet sought eligibility to 

administer a tribal plan to implement 

the good neighbor provision.85 As 

described later, the EPA is proposing to 

include all areas of Indian country 

within the covered geography, 

notwithstanding whether those areas are 

currently subject to a state’s 

implementation planning authority or 

the potential planning authority of a 

tribe. 

With respect to areas of Indian 

country not currently subject to a state’s 

implementation planning authority— 

i.e., Indian reservation lands (with the 

partial exception of reservation lands 

located in the State of Oklahoma, as 

described further below) and other areas 

of Indian country over which the EPA 

or a tribe has demonstrated that a tribe 

has jurisdiction—the EPA here proposes 

a ‘‘necessary or appropriate’’ finding 

that direct federal implementation of the 

rule’s requirements is warranted under 

CAA section 301(d)(4) and 40 CFR 

49.11(a) (the areas of Indian country 

subject to this finding are referred to 

later as the 301(d) FIP areas). Indian 

Tribes may, but are not required to, 

submit tribal plans to implement CAA 

requirements, including the good 

neighbor provision. Section 301(d) of 

the CAA and 40 CFR part 49 authorize 

the Administrator to treat an Indian 

Tribe in the same manner as a state (i.e., 

TAS) for purposes of developing and 

implementing a tribal plan 

implementing good neighbor 

obligations. See 40 CFR 49.3; see also 

‘‘Indian Tribes: Air Quality Planning 

and Management,’’ hereafter ‘‘Tribal 

Authority Rule,’’ (63 FR 7254, February 

12, 1998). The EPA is authorized to 

directly implement the good neighbor 

provision in the 301(d) FIP areas when 

it finds, consistent with the authority of 

CAA section 301—which the EPA has 

exercised in 40 CFR 49.11—that it is 

necessary or appropriate to do so.86

The EPA proposes in this action to 

find that it is both necessary and 

appropriate to regulate all new and 

existing EGU and non-EGU sources 

meeting the applicability criteria set 

forth in this proposed rule in all of the 

301(d) FIP areas that are located within 

the geographic scope of coverage of the 

rule. For purposes of this proposed 

finding, the geographic scope of 

coverage of the rule means the areas of 

the United States encompassed within 

the borders of the states EPA has 

determined to be linked at Steps 1 and 

2 of the 4-step interstate transport 

framework.87 For EGU applicability 

criteria, see Section VII.B of this 

proposed rule; for non-EGU 

applicability criteria, see Section VII.C 

of this proposed rule. To EPA’s 

knowledge, only one existing EGU or 

non-EGU source is located within the 

301(d) FIP areas: The Bonanza Power 

Plant, an EGU source, located on the 

Uintah and Ouray Reservation, 

geographically located within the 

borders of Utah. 

This proposed finding is consistent 

with EPA’s prior good neighbor rules. In 

prior rulemakings under the good 

neighbor provision, the EPA has 

included all areas of Indian country 

within the geographic scope of those 

FIPs, such that any new or existing 

sources meeting the rules’ applicability 

criteria would be subject to the rule 

irrespective of whether subject to state 

or tribal underlying CAA planning 

authority. In CSAPR, the CSAPR 

Update, and the Revised CSAPR 

Update, the scope of the emissions 

trading programs established for EGUs 

extended to cover all areas of Indian 

country located within the geographic 

boundaries of the covered states. In 

these rules, at the time of their 

promulgation, no existing units were 

located in the covered areas of Indian 

country; under the general applicability 

criteria of the trading programs, 

however, any new sources locating in 

such areas would become subject to the 

programs. Thus, EPA established a 

separate allowance allocation that 

would be available for any new units 

locating in any of the relevant areas of 

Indian country. See, e.g., 76 FR at 48293 

(describing the CSAPR methodology of 

allowance allocation under the ‘‘Indian 

country new unit set-aside’’ provisions); 

see also id. at 48217 (explaining EPA’s 

source of authority for directly 

regulating in relevant areas of Indian 

country as necessary or appropriate). 

Further, in any action in which the EPA 

subsequently approved a state’s SIP 

submittal to partially or wholly replace 

the provisions of a CSAPR FIP, EPA has 

clearly delineated that it will continue 

to administer the Indian country new 

unit set aside for sources in any areas of 

Indian country geographically located 

within a state’s borders and not subject 

to that state’s CAA planning authority, 

and the state may not exercise 

jurisdiction over any such sources. See, 

e.g., 82 FR 46674, 46677 (October 6. 

2017) (approving Alabama’s SIP 

submission establishing a state CSAPR 

trading program for ozone season NOX,

but providing, ‘‘The SIP is not approved 

to apply on any Indian reservation land 

or in any other area where EPA or an 

Indian tribe has demonstrated that a 

tribe has jurisdiction.’’). 

In this proposed rule, the EPA 

proposes to take an approach similar to 

the prior CSAPR rulemakings with 

respect to regulating sources in the 

301(d) FIP areas.88 The EPA believes 

this approach is necessary and 

appropriate for several reasons. First, 

the purpose of this rule is to address the 


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89https://www.epa.gov/system/files/documents/ 

2021-10/fy-2022-2026-epa-draft-strategic-plan.pdf 

90Executive Order 13985 (January 20, 2021): 

https://www.whitehouse.gov/briefing-room/ 

presidential-actions/2021/01/20/executiveorderadvancing-racial-equity-and-support-forunderserved-communities-through-the-federalgovernment/. 

interstate transport of ozone on a 

national scale, and the technical record 

establishes that the nonattainment and 

maintenance receptors located 

throughout the country are impacted by 

sources of ozone pollution on a broad 

geographic scale. The upwind regions 

associated with each receptor typically 

span at least two, and often far more, 

states. Within the broad upwind region 

covered by this proposal, the EPA 

proposes to apply—consistent with the 

methodology of allocating upwind 

responsibility in prior transport rules 

going back to the NOX SIP Call—a 

uniform level of control stringency. (See 

Section VI of this proposed rule for a 

discussion of EPA’s determination of 

control stringency for this proposal.) 

Within this approach, consistency in 

rule requirements across all 

jurisdictions is vital in ensuring the 

remedy for ozone transport is, in the 

words of the Supreme Court, ‘‘efficient 

and equitable,’’ 572 U.S. 489, 519. In 

particular, as the Supreme Court found 

in EME Homer City Generation, 

allocating responsibility through 

uniform levels of control across the 

entire upwind geography is ‘‘equitable’’ 

because, by imposing uniform cost 

thresholds on regulated States, EPA’s 

rule subjects to stricter regulation those 

States that have done relatively less in 

the past to control their pollution. 

Upwind States that have not yet 

implemented pollution controls of the 

same stringency as their neighbors will 

be stopped from free riding on their 

neighbors’ efforts to reduce pollution. 

They will have to bring down their 

emissions by installing devices of the 

kind in which neighboring States have 

already invested. Id. 

In the context of addressing regionalscale ozone transport in this proposal, a 

uniform level of stringency that extends 

to and includes the 301(d) FIP areas 

geographically located within the 

boundaries of the linked upwind states 

carries significant force. Failure to 

include all such areas within the scope 

of the rule creates a significant risk that 

these areas may be targeted for the siting 

of facilities emitting ozone-precursor 

pollutants, in order to avoid the 

regulatory costs that would be imposed 

under this proposed rule in the 

surrounding areas of state jurisdiction. 

Electricity generation or the production 

of other goods and commodities may 

become more cost-competitive at any 

EGUs or non-EGUs not subject to the 

rule but located in a geography where 

all surrounding facilities in the same 

industrial category are subject to the 

rule. For instance, the affected EGU 

source located on the Uintah and Ouray 

Reservation of the Ute Tribe is in an 

area that is interconnected with the 

western electricity grid and is owned 

and operated by an entity that generates 

and provides electricity to customers in 

several states. It is both necessary and 

appropriate, in EPA’s view, to avoid 

creating, via this proposed rule, a 

structure of incentives that may cause 

generation or production—and the 

associated NOX emissions—to shift into 

the 301(d) FIP areas to escape regulation 

needed to eliminate interstate transport 

under the good neighbor provision. 

The EPA believes it is appropriate to 

propose direct federal implementation 

of the proposed rule’s requirements in 

the 301(d) FIP areas at this time rather 

than at a later date. Tribes have the 

opportunity to seek TAS and to 

undertake tribal implementation plans 

under the CAA. To date, the one tribe 

which could develop and seek approval 

of a tribal implementation plan to 

address good neighbor obligations with 

respect to an existing EGU in the 301(d) 

FIP areas for the 2015 ozone NAAQS (or 

for any other NAAQS), the Ute Indian 

Tribe of the Uintah and Ouray 

Reservation, has not expressed an intent 

to do so. Nor has the EPA heard such 

intentions from any other tribe, and it 

would not be reasonable to expect tribes 

to undertake that planning effort, 

particularly when no existing sources 

are currently located on their lands. 

Further, the EPA is mindful that under 

court precedent, the EPA and states 

generally bear an obligation to fully 

implement any required emissions 

reductions to eliminate significant 

contribution under the good neighbor 

provision as expeditiously as 

practicable and in alignment with 

downwind areas’ attainment schedule 

under the Act. As discussed in Section 

VII.A of this proposed rule, the EPA 

anticipates implementing certain 

required emissions reductions by the 

2023 ozone season, the last full ozone 

season before the 2024 Moderate area 

attainment date, and other key 

additional required emissions 

reductions by the 2026 ozone season, 

the last full ozone season before the 

2027 Serious area attainment date. 

Absent this proposed federal 

implementation plan in the 301(d) FIP 

areas, NOX emissions from any existing 

or new EGU or non-EGU sources located 

in, or locating in, the 301(d) FIP areas 

within the covered geography of the rule 

would remain unregulated and could 

potentially increase. This would be 

inconsistent with EPA’s overall goal of 

aligning good neighbor obligations with 

the downwind areas’ attainment 

schedule and to achieve emissions 

reductions as expeditiously as 

practicable. 

Further, the EPA recognizes that 

Indian country, including the 301(d) FIP 

areas, is often home to communities 

with environmental justice concerns, 

and these communities may bear a 

disproportionate level of pollution 

burden as compared with other areas of 

the United States. EPA’s draft Strategic 

Plan for Fiscal Year 2022–2026 89

includes an objective to promote 

environmental justice at the Federal, 

Tribal, state, and local levels and states: 

‘‘Integration of environmental justice 

principles into all EPA activities with 

Tribal governments and in Indian 

country is designed to be flexible 

enough to accommodate EPA’s Tribal 

program activities and goals, while at 

the same time meeting the Agency’s 

environmental justice goals.’’ By 

including all areas of Indian country 

within the covered geography of the 

rule, the EPA is advancing 

environmental justice, lowering 

pollution burdens in such areas, and 

preventing the potential for ‘‘pollution 

havens’’ to form in such areas as a result 

of facilities seeking to locate there to 

avoid the requirements that would 

otherwise apply outside of such areas 

under this proposed rule. 

Therefore, in order to ensure timely 

alignment of all needed emissions 

reductions with the larger timetable of 

this proposed rule, to ensure equitable 

distribution of the upwind pollution 

reduction obligation across all upwind 

jurisdictions, to avoid perverse 

economic incentives to locate sources of 

ozone-precursor pollution in the 301(d) 

FIP areas, and to deliver greater 

environmental justice to tribal 

communities in line with Executive 

Order 13985: Advancing Racial Equity 

and Support for Underserved 

Communities Through the Federal 

Government,90 EPA proposes to find it 

both necessary and appropriate that all 

existing and new EGU and non-EGU 

sources that are located in the 301(d) 

FIP areas within the geographic 

boundaries of the covered states, and 

which would be subject to this rule if 

located within areas subject to state 

CAA planning authority, should be 

included in this rule. The EPA proposes 

this finding under section 301(d)(4) of 

the Act and 40 CFR 49.11. Further, in 

order to avoid ‘‘unreasonable delay’’ in 


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91 In ODEQ v. EPA, the D.C. Circuit held that 

under the CAA, a state has the authority to 

implement a SIP in non-reservation areas of Indian 

country in the state, where there has been no 

demonstration of tribal jurisdiction. Under the D.C. 

Circuit’s decision, the CAA does not provide 

authority to states to implement SIPs in Indian 

reservations. ODEQ did not, however, substantively 

address the separate authority in Indian country 

provided specifically to Oklahoma under 

SAFETEA. That separate authority was not invoked 

until the State submitted its request under 

SAFETEA, and was not approved until EPA’s 

decision, described in this section, on October 1, 

2020. 

92Available in the docket for this rulemaking. 

93EPA’s prior approvals relating to Oklahoma’s 

SIP frequently noted that the SIP was not approved 

to apply in areas of Indian country (consistent with 

the D.C. Circuit’s decision in ODEQ v. EPA) located 

in the state. See, e.g., 85 FR 20178, 20180 (April 10, 

2020). Such prior expressed limitations are 

superseded by EPA’s approval of Oklahoma’s 

SAFETEA request. 

94The antecedent fact that the state had the 

authority and jurisdiction to implement 

requirements under the good neighbor provision, in 

EPA’s view, supplies the condition necessary for 

the Agency to exercise its FIP authority to the 

extent the EPA has disapproved the state’s SIP 

submission with respect to those requirements. 

Under CAA section 110(c), the EPA ‘‘stands in the 

shoes of the defaulting state, and all of the rights 

and duties that would otherwise fall to the state 

accrue instead to the EPA.’’ Central Ariz. Water 

Conservation Dist. v. EPA, 990 F.2d 1531, 1541 (9th 

Cir. 1993). 

95With respect to those areas of Indian country 

constituting ‘‘excluded Indian country lands’’ in the 

State of Oklahoma, as defined above, the EPA 

proposes to apply the same necessary or 

appropriate finding as set forth above with respect 

to all other 301(d) FIP areas within the geographic 

scope of coverage of the rule. 

96On 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-andsupporting-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 

Continued 

promulgating this FIP, as required under 

section 49.11, the EPA believes it is 

appropriate to make this proposed 

finding now, in order to align emissions 

reduction obligations for any covered 

new or existing sources in the 301(d) 

FIP areas with the larger schedule of 

reductions under this proposed rule. 

Because all other covered EGU and nonEGU sources within the geography of 

this proposed rule would be subject to 

emissions reductions of uniform 

stringency beginning in the 2023 ozone 

season, and as necessary to fully and 

expeditiously address good neighbor 

obligations for the 2015 ozone NAAQS, 

there is little benefit to be had by not 

proposing to include the 301(d) FIP 

areas in this rule now and a potentially 

significant downside to not doing so. 

The Agency recognizes that Tribal 

governments may still choose to seek 

TAS to develop a Tribal plan with 

respect to the obligations under this 

proposed rule, and this proposed 

determination does not preclude the 

tribes from taking such actions. The 

EPA will continue to consult with the 

government of the Ute Indian Tribe of 

the Uintah and Ouray Reservation, and 

any other tribe wishing to continue 

consultation, during the comment 

period for this proposal. The EPA 

invites comment on this proposed 

finding. 

a. Indian Country Subject to State 

Implementation Planning Authority 

Following the U.S. Supreme Court 

decision in McGirt v. Oklahoma, 140 S. 

Ct. 2452 (2020), the Governor of the 

State of Oklahoma requested approval 

under Section 10211(a) of the Safe, 

Accountable, Flexible, Efficient 

Transportation Equity Act of 2005: A 

Legacy for Users, Public Law 109–59, 

119 Stat. 1144, 1937 (August 10, 2005) 

(‘‘SAFETEA’’), to administer in certain 

areas of Indian country (as defined at 18 

U.S.C. 1151) the State’s environmental 

regulatory programs that were 

previously approved by the EPA for 

areas outside of Indian country. The 

State’s request excluded certain areas of 

Indian country further described later. 

In addition, the State only sought 

approval to the extent that such 

approval is necessary for the State to 

administer a program in light of 

Oklahoma Dept. of Environmental 

Quality v. EPA, 740 F.3d 185 (D.C. Cir. 

2014).91

On October 1, 2020, the EPA 

approved Oklahoma’s SAFETEA request 

to administer all the State’s EPAapproved environmental regulatory 

programs, including the Oklahoma SIP, 

in the requested areas of Indian 

country.92 As requested by Oklahoma, 

the EPA’s approval under SAFETEA 

does not include Indian country lands, 

including rights-of-way running through 

the same, that: (1) Qualify as Indian 

allotments, the Indian titles to which 

have not been extinguished, under 18 

U.S.C. 1151(c); (2) are held in trust by 

the United States on behalf of an 

individual Indian or Tribe; or (3) are 

owned in fee by a Tribe, if the Tribe (a) 

acquired that fee title to such land, or 

an area that included such land, in 

accordance with a treaty with the 

United States to which such Tribe was 

a party, and (b) never allotted the land 

to a member or citizen of the Tribe 

(collectively ‘‘excluded Indian country 

lands’’). 

EPA’s approval under SAFETEA 

expressly provided that to the extent 

EPA’s prior approvals of Oklahoma’s 

environmental programs excluded 

Indian country, any such exclusions are 

superseded for the geographic areas of 

Indian country covered by EPA’s 

approval of Oklahoma’s SAFETEA 

request.93 The approval also provided 

that future revisions or amendments to 

Oklahoma’s approved environmental 

regulatory programs would extend to 

the covered areas of Indian country 

(without any further need for additional 

requests under SAFETEA). 

In a Federal Register notice published 

on February 22, 2022 (87 FR 9798), the 

EPA proposed to disapprove the portion 

of an Oklahoma SIP submittal 

pertaining to the state’s interstate 

transport obligations under CAA section 

110(a)(2)(D)(i)(I) for the 2015 ozone 

NAAQS. Consistent with the D.C. 

Circuit’s decision in ODEQ v. EPA and 

with EPA’s October 1, 2020 SAFETEA 

approval, if this disapproval is finalized 

as proposed, EPA will have authority 

under CAA section 110(c) to promulgate 

a FIP as needed to address the 

disapproved aspects of the State’s good 

neighbor SIP submittal.94 In accordance 

with the discussion above, EPA’s FIP 

authority in this circumstance would 

extend to all Indian country in 

Oklahoma, other than the excluded 

Indian country lands, as described 

previously.95 Because—per the State’s 

request under SAFETEA—EPA’s 

October 1, 2020 approval does not 

displace any SIP authority previously 

exercised by the State under the CAA as 

interpreted in ODEQ v. EPA, EPA’s FIP 

authority under CAA section 110(c) 

would also apply to any Indian 

allotments or dependent Indian 

communities located outside of an 

Indian reservation over which there has 

been no demonstration of tribal 

authority. EPA’s FIP authority under 

CAA section 110(c) would similarly 

apply to Indian allotments or dependent 

Indian communities located outside of 

an Indian reservation over which there 

has been no demonstration of tribal 

authority located in any other state 

within the geographic scope of this 

proposed rule. 

In light of the relevant legal 

authorities discussed above regarding 

the scope of the State of Oklahoma’s 

regulatory jurisdiction under the CAA, 

the EPA has FIP authority under CAA 

section 110(c) with respect to all Indian 

country in Oklahoma other than 

excluded Indian country lands. To the 

extent any change occurs in the scope 

of Oklahoma’s SIP authority in Indian 

country before the finalization of this 

proposed rule, such a change may affect 

the ability of the Agency to exercise the 

FIP authority provided under section 

110(c) of the Act.96 In that eventuality, 


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subject of a pending challenge in federal court. 

Pawnee Nation of Oklahoma v. Regan, No. 20–9635 

(10th Cir.). 

97Ramboll Environment and Health, January 

2021, http://www.camx.com. 

and to the extent any such areas would 

then fall more appropriately within the 

301(d) FIP areas as described earlier in 

this section, EPA’s proposed necessary 

or appropriate finding as set forth above 

with respect to all other 301(d) FIP areas 

within the geographic scope of coverage 

of the rule would then apply. 

V. Analyzing Downwind Air Quality 

Problems and Contributions From 

Upwind States 

A. Selection of Analytic Years for 

Evaluating Ozone Transport 

Contributions to Downwind Air Quality 

Problems 

In this section, the EPA describes its 

process for selecting analytic years for 

air quality modeling and analyses 

performed to identify nonattainment 

and maintenance receptors and identify 

upwind state linkages. For this 

proposed rule, the EPA evaluated air 

quality to identify receptors at Step 1 for 

three analytic years: 2023, 2026, and 

2032. The EPA evaluated interstate 

contributions to these receptors from 

individual upwind states at Step 2 for 

two of these analytic years: 2023 and 

2026. In selecting these years, the EPA 

views 2023 and 2026, in particular, to 

constitute years by which key emissions 

reductions from EGUs and non-EGUS 

can be implemented ‘‘as expeditiously 

as practicable.’’ (The EPA explains in 

detail in Section VII of this proposed 

rule its proposed determination that the 

necessary emissions reductions cannot 

be achieved any more quickly.) In 

addition, these years are the last full 

ozone seasons before the Moderate and 

Serious area attainment dates for the 

2015 ozone NAAQS (ozone seasons run 

each year from May 1–September 30). In 

order to demonstrate attainment by 

these deadlines, downwind states 

would be required to rely on design 

values calculated using ozone design 

values from 2021 through 2023 and 

2024 through 2026, respectively. By 

focusing its analysis, and, potentially, 

achieving emissions reductions by, the 

last full ozone seasons before the 

attainment dates (i.e., in 2023 or 2026), 

this proposed rule, if finalized, can 

assist the downwind areas with 

demonstrating attainment or receiving 

extensions of attainment dates under 

CAA section 181(a)(5). 

It would not make sense for the EPA 

to analyze any earlier year than 2023. 

EPA continues to interpret the good 

neighbor provision as forward-looking, 

based on Congress’s use of the futuretense ‘‘will’’ in section 110(a)(2)(D)(i), 

an interpretation upheld in Wisconsin, 

938 F.3d at 322. It would be 

‘‘anomalous,’’ id., for the EPA to impose 

good neighbor obligations in 2023 and 

future years based solely on finding that 

‘‘significant contribution’’ had existed at 

some time in the past. Id. 

Applying this framework in this 

proposal, the EPA recognizes that the 

2021 Marginal area attainment date has 

already passed. Further, based on the 

timing of this proposal, it will not be 

possible to finalize this rulemaking 

before the 2022 ozone season has also 

passed. Thus, EPA has selected 2023 as 

the first appropriate future analytic year 

for this proposed rule because it reflects 

implementation of good neighbor 

obligations as expeditiously as 

practicable and coincides with the 

August 3, 2024, Moderate area 

attainment date established for the 2015 

ozone NAAQS. 

The EPA conducted additional 

analysis for the 2026 and 2032 analytic 

years in order to ensure a complete Step 

3 analysis for future ozone transport 

contributions to downwind areas. These 

years also coincide with the last full 

ozone seasons before future attainment 

dates for the 2015 ozone NAAQS, and 

2026 coincides with the ozone season 

by which key additional emissions 

reductions from EGUs and non-EGUs 

become available. Thus, the EPA 

analyzed additional years beyond 2023 

to determine whether any additional 

emissions reductions that are 

impossible to obtain by the 2024 

attainment date could still be necessary 

in order to fully address significant 

contribution, taking into account the 

2027 Serious area attainment date and 

the 2033 Severe area attainment date for 

the 2015 ozone NAAQS. In all cases, the 

proposed implementation of necessary 

emissions reductions is as expeditiously 

as practicable, with all possible 

emissions reductions implemented by 

the next applicable attainment date. 

The timing framework and selection 

of analytic years set forth above 

comports with the D.C. Circuit’s 

direction in Wisconsin that 

implementing good neighbor obligations 

beyond the dates established for 

attainment may be justified on a proper 

showing of impossibility or necessity. 

See 938 F.3d at 320. 

The remainder of this section 

includes information on (1) the air 

quality modeling platform used in 

support of the proposed rule with a 

focus on the base year and future year 

base case emissions inventories, (2) the 

method for projecting design values in 

2023, 2026, and 2032, and (3) the 

approach for calculating ozone 

contributions from upwind states. The 

Agency also provides the design values 

for nonattainment and maintenance 

receptors and the predicted interstate 

contributions that are at or above the 1 

percent of the NAAQS screening 

threshold. The 2016 base period and 

2023, 2026, and 2032 future design 

values and contributions for all ozone 

monitoring sites are provided in the 

docket for this proposed rule. The Air 

Quality Modeling Technical Support 

Document (AQM TSD) in the docket for 

this proposed rule contains more 

detailed information on the air quality 

modeling aspects of this rule. 

B. Overview of Air Quality Modeling 

Platform 

The EPA used version 2 of the 2016- 

based modeling platform for the air 

quality modeling for this proposed rule. 

This modeling platform includes 2016 

base year emissions from anthropogenic 

and natural sources and 2016 

meteorology. The platform also includes 

anthropogenic emissions projections for 

2023, 2026, and 2032. The emissions 

data contained in this platform 

represent an update to the 2016 version 

1 inventories that were developed by 

the EPA, the Multi-Jurisdictional 

Organizations (MJOs), and state and 

local air agencies as part of the 

Emissions Inventory Collaborative 

Process. 

The air quality modeling for this 

proposal was performed for a modeling 

region (i.e., modeling domain) that 

covers the contiguous 48 states using a 

horizontal resolution of 12 x 12 km. The 

EPA used the CAMx version 7.10 for air 

quality modeling since this was the 

most recent version of CAMx available 

at the time the air quality modeling was 

performed.97 Additional information on 

the 2016-based air quality modeling 

platform can be found in the AQM TSD. 

C. Emissions Inventories 

The EPA developed emissions 

inventories for this proposal, including 

emissions estimates for EGUs, non-EGU 

point sources, stationary nonpoint 

sources, onroad mobile sources, 

nonroad mobile sources, other mobile 

sources, wildfires, prescribed fires, and 

biogenic emissions that are not the 

direct result of human activities. EPA’s 

air quality modeling relies on this 

comprehensive set of emissions 

inventories because emissions from 

multiple source categories are needed to 

model ambient air quality and to 

facilitate comparison of model outputs 

with ambient measurements. 


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98Biogenic 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. 

99 Detailed information and documentation of 

EPA’s Base Case, including all underlying 

assumptions, data sources, and architecture 

parameters can be found on EPA’s website at: 

https://www.epa.gov/airmarkets/epas-power-sectormodeling-platform-v6-using-ipm-summer-2021- 

reference-case. 

100Available at https://www.epa.gov/airmarkets/ 

national-electric-energy-data-system-needs-v6. 

To prepare the emissions inventories 

for air quality modeling, the EPA 

processed the emissions inventories 

using the Sparse Matrix Operator Kernel 

Emissions (SMOKE) Modeling System 

version 4.8.1 to produce the gridded, 

hourly, speciated, model-ready 

emissions for input to the air quality 

model. Additional information on the 

development of the emissions 

inventories and on data sets used during 

the emissions modeling process are 

provided in the TSD titled, ‘‘Preparation 

of Emissions Inventories for the 2016v2 

North American Emissions Modeling 

Platform,’’ hereafter known as the 

‘‘Emissions Modeling TSD.’’ This TSD is 

available in the docket for this rule. 

1. Foundation Emissions Inventory Data 

Sets 

The 2016v2 emissions platform is 

comprised of data from various sources 

including data developed using models, 

methods, and source datasets that 

became available in calendar years 2020 

and 2021, in addition to data from the 

Inventory Collaborative 2016 version 1 

(2016v1) Emissions Modeling Platform, 

released in October 2019. The 2016v1 

platform was developed through a 

national collaborative effort between the 

EPA and state and local agencies along 

with MJOs and included emissions 

inventories for the years 2016, 2023, and 

2028. For this proposed rule, emissions 

inventories were developed for the years 

2016, 2023, 2026, and 2032 that 

represent changes in activity data and of 

predicted emissions reductions from onthe-books actions, planned emissions 

control installations, and promulgated 

federal measures that affect 

anthropogenic emissions.98 The 2016 

emissions inventories for the U.S. 

include data derived from the 2017 

National Emissions Inventory (2017NEI) 

and some data derived from the 2014 

National Emissions Inventory (NEI), 

version 2 (2014NEIv2). All of the 

inventory sectors were updated to better 

represent the year 2016 through the 

incorporation of 2016-specific state and 

local data along with nationally applied 

adjustment methods. The following 

sections provide an overview of the 

construct of the 2016v2 emissions and 

projections. 

2. Development of Emissions 

Inventories for EGUs 

Annual NOX and SO2 emissions for 

EGUs in the 2016 base year inventory 

are based primarily on data from 

continuous emissions monitoring 

systems (CEMS) and other monitoring 

systems allowed for use by qualifying 

units under 40 CFR part 75, with other 

EGU pollutants estimated using 

emissions factors and annual heat input 

data reported to the EPA. For EGUs not 

reporting under part 75, the EPA used 

data submitted to the NEI and the 

2016v1 platform by the states. 

Emissions data for EGUs that did not 

have data provided for the year 2016 

were pulled forward from data 

submitted for the 2014 NEI. The Air 

Emissions Reporting Rule, (80 FR 8787; 

February 19, 2015), requires that Type A 

point sources large enough to meet or 

exceed specific thresholds for emissions 

be reported to the EPA every year, while 

the smaller Type B point sources must 

only be reported to EPA every 3 years. 

The EPA projected future 2023, 2026, 

and 2032 baseline EGU emissions using 

the version 6—Summer 2021 Reference 

Case of the Integrated Planning Model 

(IPM). IPM, developed by ICF Consulting, 

is a state-of-the-art, peer-reviewed, 

multi-regional, dynamic, deterministic 

linear programming model of the 

contiguous U.S. electric power sector. It 

provides forecasts of least cost capacity 

expansion, electricity dispatch, and 

emissions control strategies while 

meeting energy demand and 

environmental, transmission, dispatch, 

and reliability constraints. The EPA has 

used IPM for over two decades, 

including all prior implemented CSAPR 

rulemakings, to better understand power 

sector behavior under future businessas-usual conditions and to evaluate the 

economic and emissions impacts of 

prospective environmental policies. The 

model is designed to reflect electricity 

markets as accurately as possible. The 

EPA uses the best available information 

from utilities, industry experts, gas and 

coal market experts, financial 

institutions, and government statistics 

as the basis for the detailed power sector 

modeling in IPM. The model 

documentation provides additional 

information on the assumptions 

discussed here as well as all other 

model assumptions and inputs.99

The IPM version 6—Summer 2021 

Reference Case incorporated recent 

updates through the Summer of 2021 to 

account for updated federal and state 

environmental regulations (including 

Renewable Portfolio Standards (RPS), 

Clean Energy Standards (CES) and other 

state mandates), fleet changes 

(committed EGU retirements and new 

builds), electricity demand, technology 

cost and performance assumptions from 

recent data (for renewables adopting 

from National Renewable Energy Lab 

(NREL’s) Annual Technology Baseline 

2020 and for fossil sources from U.S. 

Energy Information Agency’s (EIA) 

Annual Energy Outlook (AEO) 2020. 

Natural gas and coal price projections 

reflect data developed in Fall 2020. The 

inventory of EGUs provided as an input 

to the model was the National Electric 

Energy Data System (NEEDS) Summer 

2021 version and is available on EPA’s 

website.100 This version of NEEDS 

reflects announced retirements and 

under construction new builds known 

as of early summer 2021. This projected 

base case accounts for the effects of the 

finalized Mercury and Air Toxics 

Standards rule, CSAPR, the CSAPR 

Update, the Revised CSAPR Update, 

New Source Review settlements, the 

final Effluent Limitation Guidelines 

(ELG) Rule, the Coal Combustion 

Residual (CCR) Rule, and other on-thebooks federal and state rules (including 

renewable energy tax credit extensions 

from the Consolidated Appropriations 

Act of 2021) through early 2021 

impacting SO2, NOX, directly emitted 

particulate matter, CO2, and power plant 

operations. It also includes final actions 

the EPA has taken to implement the 

Regional Haze Rule and BART 

requirements. IPM has projected output 

years for 2023 and 2025. IPM year 2025 

outputs were adjusted for known 

retirements to be reflective of year 2026, 

and IPM year 2030 outputs were used 

for the year 2032 as is specified by the 

mapping of IPM output years to specific 

years. 

Additional 2023 through 2026 EGU 

emissions baseline levels were 

developed through engineering 

analytics as an alternative approach that 

did not involve IPM. The EPA 

developed this inventory for use in Step 

3 of this final rule, where it determines 

emissions reduction potential and 

corresponding state-level emissions 

budgets. IPM includes optimization and 

perfect foresight in solving for least cost 

dispatch. Given that this final rule will 

likely become effective immediately 

prior to the start of the 2023 ozone 

season, the EPA is adopting a similar 

approach to the CSAPR Update and the 


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101https://www.faa.gov/data_research/aviation/ 

taf/. 

102http://www.wrapair2.org/pdf/WRAP_

OGWG_Report_Baseline_17Sep2019.pdf. 

Revised CSAPR Update where it relied 

on IPM in a relative way in Step 3 to 

avoid overstating optimization and 

dispatch decisions in state-emissions 

budget quantification that may not be 

possible in a short time frame. The EPA 

does this by using the difference in 

emissions rate observed between IPM 

runs with and without the cost 

threshold applied, rather than using 

absolute values. In both the CSAPR 

Update and in this rule at Step 3, EPA 

complemented that projected IPM EGU 

outlook with historical (e.g., engineering 

analytics) perspective based on 

historical data that only factors in 

known changes to the fleet. This 2023 

engineering analytics data set is 

described in more detail in the Ozone 

Transport Policy Analysis Proposed 

Rule TSD and corresponding Appendix 

A: State Emissions Budgets Calculations 

and Underlying Data. The Engineering 

Analysis used in Step 3 is also 

discussed further in Section VII.B of this 

proposed rule. 

Both IPM and the Engineering 

Analytics tools are valuable for 

estimating future EGU emissions and 

examining the cone of uncertainty 

around any future sector-level inventory 

estimate. A key difference between the 

two tools is that IPM reflects both 

announced and projected changes in 

fleet operation, whereas the Engineering 

Analytics tool only reflects announced 

changes. By not including projected 

changes that are anticipated in response 

to market forces and fleet trends, the 

Engineering Analysis is deliberately 

conservative in its estimate of change in 

the power sector. Throughout all of the 

CSAPR rules to date, and prior interstate 

transport actions, the EPA has used IPM 

at Steps 1 and 2 as it is best suited for 

projecting emissions in an airshed, at 

projecting emissions for time horizons 

more than a few years out (for which 

changes would not yet be announced 

and thus projecting changes is critical), 

and for scenarios where the assumed 

change in emissions is not being 

codified into a state emissions reduction 

requirement. Using IPM at Steps 1 and 

2 helps the EPA avoid overstating future 

year receptor values (Step 1) and future 

year linkages (Step 2) by reflecting 

reductions anticipated to occur within 

the airshed in the relevant timeframe. 

Engineering analytics has been a 

useful tool for Step 3 state-level 

emissions reduction estimates in CSAPR 

rulemaking, because at that step EPA is 

dealing with more geographic 

granularity (state-level as opposed to 

regional air shed), more near-term (as 

opposed to medium-term) assessments, 

and scenarios where reduction estimates 

are codified into regulatory 

requirements. Using the Engineering 

Analytics tool at this step ensures that 

the EPA is not codifying into the base 

case, and consequently into state 

emissions budgets, changes in the 

power sector that are merely modeled to 

occur rather than announced by realworld actors. 

Finally, both in the Revised CSAPR 

Update and in this rule, the EPA was 

able to use the Air Quality Assessment 

Tool to verify that regardless of which 

EGU inventory is used, the 2023 starting 

geography of the program is not 

impacted. In other words, regardless of 

whether a stakeholder takes a more 

comprehensive view of the EGU future 

(IPM) or a more conservative view of 

change in the EGU fleet (Engineering 

Analysis) the starting geography would 

be the same. This finding is consistent 

with the observation that EGUs are now 

less than 10% of the total ozone-season 

NOX inventory and the degree of nearterm difference between the IPM and 

Engineering Analytic regional 

projections is relatively small on the 

regional level. While the EPA continues 

to believe that IPM is best suited for 

Step 1 and Step 2, and engineering 

analytics is best suited for Step 3 efforts 

in this rulemaking, the Agency is 

requesting comment on the EGU 

emissions inventory most reasonable for 

Step 1 and Step 2 in the analysis. The 

Ozone Transport Policy Analysis 

Proposed Rule TSD contains data on 

2023 and 2026 AQ impacts of each 

dataset. 

3. Development of Emissions 

Inventories for Non-EGU Point Sources 

The updates to the non-EGU point 

source emissions include a few sources 

being moved to the EGU inventory and 

additional control efficiency 

information for the year 2016. In the 

2016v2 platform, some non-EGU point 

source emissions were based on data 

submitted for 2016, others were 

projected from 2014 to 2016, and the 

emissions for any remaining small 

sources were kept at 2014 levels. Prior 

to air quality modeling, the emissions 

inventories were processed into a format 

that is appropriate for the air quality 

model to use. The future year non-EGU 

point inventories were grown from 2016 

to the future years using factors based 

on the AEO 2021 except for limited 

cases where errors were identified with 

the AEO 2021 data in which case data 

from AEO 2020 were used. The future 

year inventories reflect emissions 

reductions due to national and local 

rules, control programs, plant closures, 

consent decrees, and settlements. 

Reductions from several Maximum 

Achievable Control Technology and 

National Emissions Standards for 

Hazardous Air Pollutants (NESHAP) 

standards are included. Projection 

approaches for corn ethanol and 

biodiesel plants, refineries and 

upstream impacts represent 

requirements pursuant to the Energy 

Independence and Security Act of 2007 

(EISA). 

Aircraft emissions and ground 

support equipment at airports are 

represented as point sources and are 

based on adjustments to emissions in 

the January 2021 version of the 2017 

NEI (see https://www.epa.gov/airemissions-inventories/2017-nationalemissions-inventory-nei-data for data 

and a TSD). A notable update in the 

January 2021 version of the 2017 NEI as 

compared to the April 2020 version was 

a correction to some double counting of 

some airport emissions. This correction 

is incorporated into the inventories for 

this proposed rule. The EPA developed 

and applied factors to adjust the 2017 

airport emissions to 2016, 2023, 2026, 

and 2032 based on activity growth 

projected by the Federal Aviation 

Administration 2019 Terminal Area 

Forecast 101 system, the latest available 

version at the time the factors were 

developed. 

Emissions at rail yards were 

represented as point sources. The 2016 

rail yard emissions are largely 

consistent with the 2017 NEI rail yard 

emissions. The 2016 and 2023 rail yard 

emissions were developed through the 

2016v1 Inventory Collaborative process, 

with the 2026 emissions interpolated 

between the 2023 and 2028 emissions 

from 2016v1 rail yard emissions were 

interpolated from the 2016 and 2023 

emissions. Class I rail yard emissions 

were projected based on the AEO freight 

rail energy use growth rate projections 

for 2016, 2023, and 2032 with the fleet 

mix assumed to be constant throughout 

the period. 

Point source oil and gas emissions for 

2016 were based on the 2016v1 point 

inventory except that an inventory 

generated by the Western Regional Air 

Partnership (WRAP) 102 was used for the 

states of Colorado, Montana, New 

Mexico, North Dakota, South Dakota, 

Utah, and Wyoming. The 2016 oil and 

gas inventories were first projected to 

2019 values based on actual production 

data, and those 2019 emissions were 

projected to 2023, 2026, and 2032 using 

regional projection factors by product 

type based on AEO 2021 projections. 

NOX and VOC reductions that are coVerDate Sep<11>2014 20:07 Apr 05, 2022 Jkt 256001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 E:\FR\FM\06APP2.SGM 06APP2

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103On November 15, 2021, the EPA published 

proposed revisions to standards of performance for 

new, reconstructed, and modified sources and 

proposed revisions to emissions guidelines for 

existing sources in the oil and natural gas sector at 

86 FR 63110. Emissions reductions from proposed 

federal regulatory programs are not included in 

EPA’s baseline analyses until they have been 

finalized. 

104http://www.wrapair2.org/pdf/WRAP_OGWG

_2028_OTB_RevFinalReport_05March2020.pdf. 

105The effect of the HDGHG Phase 2 rule on 

criteria pollutants is estimated in Table 5–48 of the 

Regulatory Impact Analysis, available from https:// 

nepis.epa.gov/Exe/ZyPDF.cgi/P100P7NS.PDF

?Dockey=P100P7NS.PDF. 

106 Information on the SAFE vehicles rule is 

available from https://www.epa.gov/regulationsemissions-vehicles-and-engines/safer-affordablefuel-efficient-safe-vehicles-final-rule. Preliminary 

analysis by the Office of Transportation and Air 

Quality of the impact of this rule on criteria 

pollutants show impacts of less than 1 percent for 

VOC and no impact for NOX. 

107CMV emissions were projected out to 2030 

instead of 2032 because that was the last year of 

data available in a dataset used in the projections 

process. The year 2030 inventories were used in the 

2032 emissions case. 

benefits to the NESHAP and New 

Source Performance Standards (NSPS) 

for Stationary Reciprocating Internal 

Combustion Engines (RICE) are reflected 

for select source categories. In addition, 

Natural Gas Turbines and Process 

Heaters NSPS NOX controls and NSPS 

Oil and Gas VOC controls 103 are 

reflected for select source categories. 

The WRAP future year inventory was 

used in WRAP states in all future 

years.104

4. Development of Emissions 

Inventories for Onroad Mobile Sources 

Onroad mobile sources include 

exhaust, evaporative, and brake and tire 

wear emissions from vehicles that drive 

on roads, parked vehicles, and vehicle 

refueling. Emissions from vehicles using 

regular gasoline, high ethanol gasoline, 

diesel fuel, and electric vehicles were 

represented, along with buses that used 

compressed natural gas. The EPA 

developed the onroad mobile source 

emissions for states other than 

California using EPA’s Motor Vehicle 

Emissions Simulator (MOVES). 

MOVES3 was released in November 

2020 and has been followed by some 

minor releases that improved the usage 

of the model but that do not have 

substantive impacts on the emissions 

estimates. For this proposal, MOVES3 

was run using inputs provided by state 

and local agencies through the 2017 NEI 

where available, in combination with 

nationally available data sets to develop 

a complete inventory. Onroad emissions 

for 2016v2 were developed based on 

emissions factors output from MOVES3 

run for the year 2016, coupled with 

activity data (e.g., vehicle miles traveled 

and vehicle populations) representing 

the year 2016. The 2016 activity data 

were provided by some state and local 

agencies through the 2016v1 process, 

and the remaining activity data were 

derived from the 2017 NEI. The onroad 

emissions were computed within 

SMOKE by multiplying emissions 

factors developed using MOVES with 

the appropriate activity data. Onroad 

mobile source emissions for California 

were consistent with the emissions data 

provided by the state. 

The future-year emissions estimates 

for onroad mobile sources represent all 

national control programs known at the 

time of modeling including rules newly 

added in MOVES3: The Greenhouse Gas 

Emissions and Fuel Efficiency 

Standards for Medium- and Heavy-Duty 

Engines and Vehicles (HDGHG)—Phase 

2 105 and the Safer Affordable FuelEfficient (SAFE) Vehicles Rule.106 Other 

finalized rules incorporated into the 

onroad mobile source emissions 

estimates include: Tier 3 Standards 

(March 2014), the Light-Duty 

Greenhouse Gas Rule (March 2013), 

Heavy (and Medium)-Duty Greenhouse 

Gas Rule (August 2011), the Renewable 

Fuel Standard (February 2010), the 

Light Duty Greenhouse Gas Rule (April 

2010), the Corporate-Average Fuel 

Economy standards for 2008–2011 

(April 2010), the 2007 Onroad HeavyDuty Rule (February 2009), and the 

Final Mobile Source Air Toxics Rule 

(MSAT2) (February 2007). Estimates of 

the impacts of rules that were in effect 

in 2016 are included in the 2016 base 

year emissions at a level that 

corresponds to the extent to which each 

rule had penetrated into the fleet and 

fuel supply by the year 2016. Local 

control programs such as the California 

LEV III program for criteria pollutants 

are included in the onroad mobile 

source emissions. 

The future year onroad emissions 

reflect projected changes to fuel 

properties and usage, along with the 

impact of the rules included in 

MOVES3 for each of the future years. 

MOVES was run for the years 2023, 

2026, and 2032 to generate the 

emissions factors relevant to those 

years. Future year activity data for 

onroad mobile sources were provided 

by some state and local agencies, and 

otherwise were projected to 2023, 2026, 

and 2032 by first projecting the 2016 

activity to year 2019 based on county 

level vehicle miles traveled (VMT) from 

the Federal Highway Administration, 

and then from 2019 to the future years 

using AEO 2021-based factors. The 

future year emissions were computed 

within SMOKE by multiplying the 

future year emissions factors developed 

using MOVES with the year-specific 

activity data. 

5. Development of Emissions 

Inventories for Commercial Marine 

Vessels 

The commercial marine vessel (CMV) 

emissions in the 2016 base case 

emissions inventory for this rule were 

based on those in the 2017 NEI. Factors 

were then applied to adjust the 2017 

NEI emissions backward to represent 

emissions for the year 2016. The CMV 

emissions reflect reductions associated 

with the Emissions Control Area 

proposal to the International Maritime 

Organization control strategy (EPA– 

420–F–10–041, August 2010); 

reductions of NOX, VOC, and CO 

emissions for new C3 engines that went 

into effect in 2011; and fuel sulfur limits 

that went into effect prior to 2016. The 

cumulative impacts of these rules 

through 2023, 2026 and 2030 107 were 

incorporated into the projected 

emissions for CMV sources. The CMV 

emissions were split into emissions 

inventories from the larger category 3 

(C3) engines, and those from the smaller 

category 1 and 2 (C1C2) engines. CMV 

emissions in California are based on 

emissions provided by the state. The 

CMV emissions are consistent with the 

emissions for the 2016v1 platform 

updated CMV emissions released by 

February 2020 although they include 

future years of 2026 and 2030 instead of 

2028. 

6. Development of Emissions 

Inventories for Other Nonroad Mobile 

Sources 

Nonroad mobile source emissions 

inventories (other than CMV, 

locomotive, and aircraft emissions) were 

developed from monthly, county, and 

process level emissions output from 

MOVES3. Types of nonroad equipment 

include recreational vehicles, pleasure 

craft, and construction, agricultural, 

mining, and lawn and garden 

equipment. State-submitted emissions 

data for nonroad sources were used for 

California. 

The EPA also ran MOVES3 for 2023, 

2026, and 2032 to prepare nonroad 

mobile emissions inventories for future 

years. The nonroad mobile emissions 

control programs include reductions to 

locomotives, diesel engines, and 

recreational marine engines, along with 

standards for fuel sulfur content and 

evaporative emissions. A 

comprehensive list of control programs 

included for mobile sources is available 

in the Emissions Modeling TSD. 


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108The farthest out year for which locomotive 

emissions were projected was 2030 and those were 

used in the 2032 case. 

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

110http://www.wrapair2.org/pdf/WRAP_

OGWG_2028_OTB_RevFinalReport_

05March2020.pdf. 

111 531 F.3d at 910–911 (holding that the EPA 

must give ‘‘independent significance’’ to each prong 

of CAA section 110(a)(2)(D)(i)(I)). 

112See 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). 

Line haul locomotives are also 

considered a type of nonroad mobile 

source but the emissions inventories for 

locomotives were not developed using 

MOVES3. Year 2016 and 2023 

locomotive emissions were developed 

through the 2016v1 process and the year 

2016 emissions are mostly consistent 

with those in the 2017 NEI. The 

projected locomotive emissions for 

2023, 2026, and 2030 108 were 

developed by applying factors to the 

base year emissions using activity data 

based on AEO freight rail energy use 

growth rate projections along with 

emissions rates adjusted to account for 

recent historical trends. 

7. Development of Emissions 

Inventories for Nonpoint Sources 

Some emissions for stationary 

nonpoint sources in the 2016 base case 

emissions inventory come from the 2017 

NEI adjusted to 2016 levels, while 

others are based on data from the 

2014NEIv2 adjusted to reflect year 2016 

more closely using factors based on 

changes to human population from 2014 

to 2016. Stationary nonpoint sources 

include evaporative sources, consumer 

products, fuel combustion that is not 

captured by point sources, agricultural 

livestock, agricultural fertilizer, 

residential wood combustion, fugitive 

dust, and oil and gas sources. The 

emissions sources based on the 2017 

NEI include agricultural livestock, 

fugitive dust, residential wood 

combustion, waste disposal (including 

composting), bulk gasoline terminals, 

and miscellaneous non-industrial 

sources such as cremation, hospitals, 

lamp breakage, and automotive repair 

shops. A new method for solvent VOC 

emissions was used.109

Where states provided the Inventory 

Collaborative information about 

projected control measures or changes 

in nonpoint source emissions for 

2016v1 or 2016v2, those inputs were 

incorporated into the projected 

inventories for 2023, 2026, and 2032 to 

the extent possible. Where possible, 

projection factors based on the AEO 

were based on AEO 2021. Adjustments 

for state fuel sulfur content rules for fuel 

oil in the Northeast were included. 

Projected emissions for portable fuel 

containers reflect the impact of 

projection factors required by the final 

MSAT2 rule and the EISA, including 

updates to cellulosic ethanol plants, 

ethanol transport working losses, and 

ethanol distribution vapor losses. 

For 2016, nonpoint oil and gas 

emissions inventories were developed 

based on a run of the 2017 NEI version 

of the EPA Oil and Gas Tool with data 

for year 2016 coupled with the WRAP 

inventory for production-related 

nonpoint oil and gas emissions in the 

states of Colorado, Montana, New 

Mexico, North Dakota, South Dakota, 

Utah, and Wyoming, and a California 

Air Resources Board-provided inventory 

was used for emissions in California. 

Nonpoint oil and gas emissions in other 

states and exploration-related emissions 

in the WRAP states were based on a run 

of the 2017 NEI version of the EPA Oil 

and Gas Tool with input data for the 

year 2016. The 2016 oil and gas 

inventories were first projected to 2019 

values based on actual production data, 

and those 2019 emissions were 

projected to 2023, 2026, and 2032 using 

regional projection factors by product 

type based on AEO 2021 projections. 

NOX and VOC reductions that are cobenefits to the NESHAP and NSPS for 

RICE are reflected for select source 

categories. In addition, Natural Gas 

Turbines and Process Heaters NSPS 

NOX controls and NSPS Oil and Gas 

VOC controls are reflected for select 

source categories. The WRAP future 

year inventory was used in WRAP states 

in all future years.110

D. Air Quality Modeling To Identify 

Nonattainment and Maintenance 

Receptors 

In this section, the Agency describes 

the air quality modeling and analyses 

performed in Step 1 to identify locations 

where the Agency expects there to be 

nonattainment or maintenance receptors 

for the 2015 ozone NAAQS in the 2023, 

2026, and 2032 analytic future years. 

Where EPA’s analysis shows that an 

area or site does not fall under the 

definition of a nonattainment or 

maintenance receptor in 2023, that site 

is excluded from further analysis under 

EPA’s good neighbor framework. 

In this proposed rule, the EPA is 

applying the same approach used in the 

CSAPR Update and the Revised CSAPR 

Update to identify nonattainment and 

maintenance receptors for the 2008 

ozone NAAQS. See 86 FR 23078–79. 

EPA’s approach gives independent 

effect to both the ‘‘contribute 

significantly to nonattainment’’ and the 

‘‘interfere with maintenance’’ prongs of 

section 110(a)(2)(D)(i)(I), consistent with 

the D.C. Circuit’s direction in North 

Carolina.111 Further, in its decision on 

the remand of the CSAPR from the 

Supreme Court in the EME Homer City 

case, the D.C. Circuit confirmed that 

EPA’s approach to identifying 

maintenance receptors in the CSAPR 

comported with the court’s prior 

instruction to give independent 

meaning to the ‘‘interfere with 

maintenance’’ prong in the good 

neighbor provision. EME Homer City II, 

795 F.3d at 136. 

In the CSAPR Update and the Revised 

CSAPR Update, the EPA identified 

nonattainment receptors as those 

monitoring sites that are projected to 

have average design values that exceed 

the NAAQS and that are also measuring 

nonattainment based on the most recent 

monitored design values. This approach 

is consistent with prior transport 

rulemakings, such as the NOX SIP Call 

and CAIR, where the EPA defined 

nonattainment receptors as those areas 

that both currently monitor 

nonattainment and that the EPA projects 

will be in nonattainment in the future 

compliance year.112

The Agency explained in the NOX SIP 

Call and CAIR and then reaffirmed in 

the CSAPR Update that the EPA has the 

most confidence in our projections of 

nonattainment for those counties that 

also measure nonattainment for the 

most recent period of available ambient 

data. The EPA separately identified 

maintenance receptors as those 

receptors that would have difficulty 

maintaining the relevant NAAQS in a 

scenario that accounts for historical 

variability in air quality at that receptor. 

The variability in air quality was 

determined by evaluating the 

‘‘maximum’’ future design value at each 

receptor based on a projection of the 

maximum measured design value over 

the relevant period. The EPA interprets 

the projected maximum future design 

value to be a potential future air quality 

outcome consistent with the 

meteorology that yielded maximum 

measured concentrations in the ambient 

data set analyzed for that receptor (i.e., 

ozone conducive meteorology). The EPA 

also recognizes that previously 

experienced meteorological conditions 

(e.g., dominant wind direction, 

temperatures, and air mass patterns) 

promoting ozone formation that led to 

maximum concentrations in the 

measured data may reoccur in the 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20067 

113The 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. 

114See 795 F.3d at 136. 

115The EPA issued a memorandum in October 

2018, providing additional information to states 

developing interstate transport SIP submissions for 

the 2015 8-hour ozone NAAQS concerning 

considerations for identifying downwind areas that 

may have problems maintaining the standard at 

Step 1 of the 4-step interstate transport framework. 

See Considerations for Identifying Maintenance 

Receptors for Use in Clean Air Act Section 

110(a)(2)(D)(i)(I) Interstate Transport State 

Implementation Plan Submissions for the 2015 

Ozone National Ambient Air Quality Standards, 

October 19, 2018 (‘‘October 2018 memorandum’’), 

available in Docket No. EPA–HQ–OAR–2021–0663 

or at https://www.epa.gov/airmarkets/memo-andsupplemental-information-regarding-interstatetransport-sips-2015-ozone-naaqs. The EPA does not 

propose to adopt the information or suggested 

analytical approaches in that memorandum in this 

proposed rule proposing FIPs. Potential alternative 

approaches would introduce unnecessary and 

substantial additional analytical burdens that could 

frustrate timely and efficient implementation of 

good neighbor obligations. In addition, the 

information supplied in that memorandum is now 

outdated due to several additional years of air 

quality monitoring data and updated modeling 

results. EPA’s current approach to defining 

‘‘maintenance’’ receptors has been upheld and 

continues to provide an appropriate approach to 

addressing the ‘‘interference with maintenance’’ 

prong of the Good Neighbor provision. See EME 

Homer City, 795 F.3d 118, 136–37; Wisconsin, 938 

F.3d at 325–26. 

116The 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. 117As noted above, each model grid cell is 12 x 

12 km. 

118The relative response factor represents the 

change in ozone at a given site. In order to calculate 

the RRF, EPA’s modeling guidance recommends 

selecting the 10 highest ozone days in an ozone 

season at a given monitor in the base year, noting 

which of the grid cells surrounding the monitor 

experienced the highest ozone concentrations in the 

base year, and averaging those ten highest 

concentrations. The model is then run using the 

projected year emissions, in this case 2023, with all 

other model variables held constant. Ozone 

concentrations from the same ten days, in the same 

grid cells, are then averaged. The fractional change 

between the base year (2016 model run) averaged 

ozone concentrations and the future year (e.g., 2023 

model run) averaged ozone concentrations 

represents the relative response factor. 

119https://www.mmm.ucar.edu/weather-researchand-forecasting-model. 

future. The maximum design value 

gives a reasonable projection of future 

air quality at the receptor under a 

scenario in which such conditions do, 

in fact, reoccur.113 The projected 

maximum design value is used to 

identify upwind emissions that, under 

those circumstances, could interfere 

with the downwind area’s ability to 

maintain the NAAQS. 

Therefore, applying this methodology 

in this proposed rule, EPA assessed the 

magnitude of the maximum projected 

design values for 2023, 2026, and 2032 

at each receptor in relation to the 2015 

ozone NAAQS and, where such a value 

exceeds the NAAQS, the EPA 

determined that receptor to be a 

‘‘maintenance’’ receptor for purposes of 

defining interference with maintenance, 

consistent with the method used in 

CSAPR and upheld by the D.C. Circuit 

in EME Homer City II.114 That is, 

monitoring sites with a maximum 

design value that exceeds the NAAQS 

are projected to have maintenance 

problems in the future analytic years.115

Recognizing that nonattainment 

receptors are also, by definition, 

maintenance receptors, the EPA often 

uses the term ‘‘maintenance-only’’ to 

refer to receptors that are not also 

nonattainment receptors. Consistent 

with the concepts for maintenance 

receptors, as described above, the EPA 

identifies ‘‘maintenance-only’’ receptors 

as those monitoring sites that have 

projected average design values above 

the level of the applicable NAAQS, but 

that are not currently measuring 

nonattainment based on the most recent 

official design values. In addition, those 

monitoring sites with projected average 

design values below the NAAQS, but 

with projected maximum design values 

above the NAAQS are also identified as 

‘‘maintenance only’’ receptors, even if 

they are currently measuring 

nonattainment based on the most recent 

official design values. 

Consistent with EPA’s modeling 

guidance, the 2016 base year and future 

year air quality modeling results were 

used in a relative sense to project design 

values for 2023, 2026, and 2032. That is, 

the ratios of future year model 

predictions to base year model 

predictions are used to adjust ambient 

ozone design values 116 up or down 

depending on the relative (percent) 

change in model predictions for each 

location. The modeling guidance 

recommends using measured ozone 

concentrations for the 5-year period 

centered on the base year as the air 

quality data starting point for future 

year projections. This average design 

value is used to dampen the effects of 

inter-annual variability in meteorology 

on ozone concentrations and to provide 

a reasonable projection of future air 

quality at the receptor under average 

conditions. In addition, the Agency 

calculated maximum design values from 

within the 5-year base period to 

represent conditions when meteorology 

is more favorable than average for ozone 

formation. Because the base year for the 

air quality modeling used in this 

proposed rule is 2016, measured data 

for 2014–2018 (i.e., design values for 

2016, 2017, and 2018) were used in 

order to project average and maximum 

design values in 2023, 2026, and 2032. 

The ozone predictions from the 2016 

and future year air quality model 

simulations were used to project 2016– 

2018 average and maximum ozone 

design values to 2023, 2026, and 2032 

using an approach similar to the 

approach in EPA’s guidance for 

attainment demonstration modeling. 

This guidance recommends using model 

predictions from the 3 x 3 array of grid 

cells 117 surrounding the location of the 

monitoring site to calculate a Relative 

Response Factor (RRF) for that site.118

The 2016–2018 base period average and 

maximum design values were 

multiplied by the RRF to project each of 

these design values to each of the three 

future years. In this manner, the 

projected design values are grounded in 

monitored data, and not the absolute 

model-predicted future year 

concentrations. Following the approach 

in the CSAPR Update and the Revised 

CSAPR Update, the EPA also projected 

future year design values based on a 

modified version of the ‘‘3 x 3’’ 

approach for those monitoring sites 

located in coastal areas. In this 

alternative approach, EPA eliminated 

from the RRF calculations the modeling 

data in those grid cells that are 

dominated by water (i.e., more than 50 

percent of the area in the grid cell is 

water) and that do not contain a 

monitoring site (i.e., if a grid cell is more 

than 50 percent water but contains an 

air quality monitor, that cell would 

remain in the calculation). The choice of 

more than 50 percent of the grid cell 

area as water as the criteria for 

identifying overwater grid cells is based 

on the treatment of land use in the 

Weather Research and Forecasting 

model (WRF).119 Specifically, in the 

WRF meteorological model those grid 

cells that are greater than 50% 

overwater are treated as being 100 

percent overwater. In such cases the 

meteorological conditions in the entire 

grid cell reflect the vertical mixing and 

winds over water, even if part of the 

grid cell also happens to be over land 

with land-based emissions, as can often 

be the case for coastal areas. Overlaying 

land-based emissions with overwater 

meteorology may be representative of 

conditions at coastal monitors during 

times of on-shore flow associated with 

synoptic conditions or sea-breeze or 

lake-breeze wind flows. But there may 

be other times, particularly with offshore wind flow, when vertical mixing 

of land-based emissions may be too 


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20068 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

120Using design values from the ‘‘3 x 3’’ 

approach, the maintenance-only receptor at site 

170317002 in Cook County, IL would become a 

nonattainment receptor because the average design 

value with the ‘‘3 x 3’’ approach is 71.1 ppb versus 

70.1 ppb with the ‘‘no water’’ approach. In addition, 

the monitor at site 170971007 in Lake County, IL 

which was not projected to be a receptor using the 

‘‘no water’’ approach would be a maintenance-only 

receptor with the ‘‘3 x 3’’ approach because the 

maximum design value with the ‘‘no water’’ 

approach was 69.9 ppb versus a maximum design 

value of 71.2 ppb with the ‘‘3 x 3’’ approach. 

However, including this Lake County, Illinois site 

as a receptor would not affect which states are 

covered by this proposed rule. 

121 40 CFR part 50, Appendix P to Part 50— 

Interpretation of the Primary and Secondary 

National Ambient Air Quality Standards for Ozone. 

122 2016-centered averaged design values 

represent the average of the design values for 2016, 

2017, and 2018. Similarly, the maximum 2016- 

centered design value is the highest measured 

design value from these three design value periods. 

limited due to the presence of overwater 

meteorology. Thus, for our modeling 

EPA projected average and maximum 

design values at individual monitoring 

sites based on both the ‘‘3 x 3’’ approach 

as well as the alternative approach that 

eliminates overwater cells in the RRF 

calculation for near-coastal areas (i.e., 

‘‘no water’’ approach). The projected 

2023, 2026, and 2032 design values 

using both the ‘‘3 x 3’’ and ‘‘no-water’’ 

approaches are provided in the docket 

for this proposed rule. For this proposed 

rule, the EPA is relying upon design 

values based on the ‘‘no water’’ 

approach for identifying nonattainment 

and maintenance receptors.120

Consistent with the truncation and 

rounding procedures for the 8-hour 

ozone NAAQS, the projected design 

values are truncated to integers in units 

of ppb.121 Therefore, projected design 

values that are greater than or equal to 

71 ppb are considered to be violating 

the 2015 ozone NAAQS. For those sites 

that are projected to be violating the 

NAAQS based on the average design 

values in the future analytic years, the 

Agency examined the measured design 

values for 2020, which are the most 

recent official measured design values at 

the time of this proposal. As noted 

earlier, the Agency proposes to identify 

nonattainment receptors in this 

rulemaking as those sites that are 

violating the NAAQS based on current 

measured air quality and also have 

projected average design values of 71 

ppb or greater. Maintenance-only 

receptors include both (1) those sites 

with projected average design values 

above the NAAQS that are currently 

measuring clean data and (2) those sites 

with projected average design values 

below the level of the NAAQS, but with 

projected maximum design values of 71 

ppb or greater. In addition to the 

maintenance-only receptors, the 2021 

ozone nonattainment receptors are also 

maintenance receptors because the 

maximum design values for each of 

these sites is always greater than or 

equal to the average design value. The 

monitoring sites that the Agency 

projects to be nonattainment and 

maintenance receptors for the ozone 

NAAQS in the 2023 and 2026 base case 

are used for assessing the contribution 

of emissions in upwind states to 

downwind nonattainment and 

maintenance of ozone NAAQS as part of 

this proposal. 

Table V.D–1 contains the 2016- 

centered 122 base period average and 

maximum 8-hour ozone design values, 

the 2023 base case average and 

maximum design values and the 2020 

design values for the sites that are 

projected to be nonattainment receptors 

in 2023. Table V.D–2 contains this same 

information for monitoring sites that are 

projected to be maintenance-only 

receptors in 2023. The design values for 

all monitoring sites in the U.S. are 

provided in the docket for this rule. 

Additional details on the approach for 

projecting average and maximum design 

values are provided in the AQM TSD. 

TABLE V.D–1—AVERAGE AND MAXIMUM 2016-CENTERED AND 2023 BASE CASE 8-HOUR OZONE DESIGN VALUES AND

2020 DESIGN VALUES (ppb) AT PROJECTED NONATTAINMENT RECEPTORS * 

Monitor ID State County 

2016 

centered 

average 

2016 

centered 

maximum 

2023 

average 

2023 

maximum 2020 

060170010 .................... CA El Dorado ..................... 85.3 88 76.3 78.7 84 

060170020 .................... CA El Dorado ..................... 82.0 84 74.3 76.2 80 

060190007 .................... CA Fresno .......................... 87.0 89 80.4 82.2 80 

060190011 .................... CA Fresno .......................... 90.0 91 82.9 83.8 84 

060190242 .................... CA Fresno .......................... 84.3 86 79.5 81.1 79 

060194001 .................... CA Fresno .......................... 90.3 92 82.8 84.4 81 

060195001 .................... CA Fresno .......................... 91.0 94 83.7 86.4 84 

060250005 .................... CA Imperial ......................... 76.7 77 76.3 76.6 78 

060251003 .................... CA Imperial ......................... 76.0 76 75.4 75.4 68 

060290007 .................... CA Kern .............................. 87.7 89 82.8 84.0 93 

060290008 .................... CA Kern .............................. 83.0 85 79.1 81.0 85 

060290011 .................... CA Kern .............................. 83.3 85 78.8 80.4 86 

060290014 .................... CA Kern .............................. 86.0 88 81.3 83.2 85 

060290232 .................... CA Kern .............................. 79.3 82 74.9 77.5 83 

060292012 .................... CA Kern .............................. 89.3 90 84.1 84.7 85 

060295002 .................... CA Kern .............................. 87.3 89 82.4 84.0 89 

060296001 .................... CA Kern .............................. 80.7 81 77.1 77.4 82 

060311004 .................... CA Kings ............................. 83.3 84 76.9 77.6 80 

060370002 .................... CA Los Angeles .................. 94.3 99 88.0 92.4 97 

060370016 .................... CA Los Angeles .................. 100.0 103 93.4 96.2 107 

060371201 .................... CA Los Angeles .................. 88.3 91 82.7 85.3 92 

060371602 .................... CA Los Angeles .................. 75.7 76 73.6 73.9 78 

060371701 .................... CA Los Angeles .................. 92.0 95 85.6 88.4 88 

060372005 .................... CA Los Angeles .................. 84.7 86 80.7 81.9 93 

060376012 .................... CA Los Angeles .................. 98.0 100 91.6 93.4 101 

060379033 .................... CA Los Angeles .................. 87.3 89 80.7 82.2 80 

060390004 .................... CA Madera ......................... 80.3 83 75.7 78.3 76 

060392010 .................... CA Madera ......................... 82.7 84 77.0 78.2 78 

060430003 .................... CA Mariposa ....................... 76.0 79 74.2 77.1 79 

060470003 .................... CA Merced .......................... 80.7 82 74.7 75.9 76 

060570005 .................... CA Nevada ......................... 86.3 90 78.1 81.5 82 


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TABLE V.D–1—AVERAGE AND MAXIMUM 2016-CENTERED AND 2023 BASE CASE 8-HOUR OZONE DESIGN VALUES AND

2020 DESIGN VALUES (ppb) AT PROJECTED NONATTAINMENT RECEPTORS *—Continued 

Monitor ID State County 

2016 

centered 

average 

2016 

centered 

maximum 

2023 

average 

2023 

maximum 2020 

060592022 .................... CA Orange .......................... 77.7 78 72.5 72.8 82 

060595001 .................... CA Orange .......................... 75.3 76 72.3 73.0 77 

060610003 .................... CA Placer ........................... 85.0 88 77.1 79.8 N/A 

060610004 .................... CA Placer ........................... 79.3 85 71.9 77.0 N/A 

060610006 .................... CA Placer ........................... 80.0 81 72.8 73.7 72 

060650008 .................... CA Riverside ....................... 76.5 79 71.0 73.3 N/A 

060650012 .................... CA Riverside ....................... 95.3 98 85.9 88.3 99 

060650016 .................... CA Riverside ....................... 79.0 80 72.0 72.9 78 

060651016 .................... CA Riverside ....................... 99.7 101 89.8 90.9 99 

060652002 .................... CA Riverside ....................... 82.7 85 76.4 78.5 84 

060655001 .................... CA Riverside ....................... 88.7 91 80.5 82.6 88 

060656001 .................... CA Riverside ....................... 92.3 93 83.5 84.1 94 

060658001 .................... CA Riverside ....................... 96.7 98 89.5 90.7 96 

060658005 .................... CA Riverside ....................... 95.0 98 87.9 90.7 98 

060659001 .................... CA Riverside ....................... 88.7 91 80.8 82.9 87 

060670002 .................... CA Sacramento .................. 77.7 78 71.4 71.7 72 

060670012 .................... CA Sacramento .................. 82.3 83 74.8 75.4 N/A 

060710001 .................... CA San Bernardino ............ 79.0 80 74.5 75.4 81 

060710005 .................... CA San Bernardino ............ 110.3 112 100.3 101.8 109 

060710012 .................... CA San Bernardino ............ 95.0 98 87.3 90.1 90 

060710306 .................... CA San Bernardino ............ 84.0 86 76.8 78.6 83 

060711004 .................... CA San Bernardino ............ 105.7 109 97.2 100.2 106 

060712002 .................... CA San Bernardino ............ 97.7 99 90.1 91.3 102 

060714001 .................... CA San Bernardino ............ 90.3 91 82.6 83.3 87 

060714003 .................... CA San Bernardino ............ 104.0 107 95.2 98.0 114 

060719002 .................... CA San Bernardino ............ 87.3 89 80.1 81.6 86 

060719004 .................... CA San Bernardino ............ 108.7 111 99.5 101.6 110 

060731006 .................... CA San Diego ..................... 83.0 84 76.9 77.9 79 

060773005 .................... CA San Joaquin ................. 77.3 79 71.3 72.8 70 

060990005 .................... CA Stanislaus ..................... 81.0 82 75.4 76.3 79 

060990006 .................... CA Stanislaus ..................... 83.7 84 77.5 77.8 80 

061030004 .................... CA Tehama ........................ 79.7 81 72.3 73.4 74 

061070006 .................... CA Tulare ........................... 84.7 86 79.1 80.3 83 

061070009 .................... CA Tulare ........................... 89.0 89 82.6 82.6 88 

061072002 .................... CA Tulare ........................... 82.7 85 75.5 77.6 83 

061072010 .................... CA Tulare ........................... 84.0 86 77.0 78.8 80 

061090005 .................... CA Tuolumne ...................... 80.7 83 75.6 77.8 77 

080350004 .................... CO Douglas ........................ 77.3 78 71.7 72.3 81 

080590006 .................... CO Jefferson ....................... 77.3 78 72.6 73.3 79 

080590011 .................... CO Jefferson ....................... 79.3 80 73.8 74.4 80 

080690011 .................... CO Larimer ......................... 75.7 77 71.3 72.6 75 

090010017 .................... CT Fairfield ......................... 79.3 80 73.0 73.7 82 

090013007 .................... CT Fairfield ......................... 82.0 83 74.2 75.1 80 

090019003 .................... CT Fairfield ......................... 82.7 83 76.1 76.4 79 

090099002 .................... CT New Haven ................... 79.7 82 71.8 73.9 80 

481671034 .................... TX Galveston ..................... 75.7 77 71.1 72.3 74 

482010024 .................... TX Harris ............................ 79.3 81 75.2 76.8 79 

482010055 .................... TX Harris ............................ 76.0 77 71.0 72.0 76 

490110004 .................... UT Davis ............................. 75.7 78 72.9 75.1 77 

490353006 .................... UT Salt Lake ...................... 76.3 78 73.6 75.3 74 

490353013 .................... UT Salt Lake ...................... 76.5 77 74.4 74.9 73 

550590019 .................... WI Kenosha ....................... 78.0 79 72.8 73.7 74 

551010020 .................... WI Racine .......................... 76.0 78 71.3 73.2 73 

551170006 .................... WI Sheboygan ................... 80.0 81 73.6 74.5 75 

* ‘‘N/A’’ is used to denote that there is no valid 2020 design value. 

TABLE V.D–2—AVERAGE AND MAXIMUM 2016-CENTERED AND 2023 BASE CASE 8-HOUR OZONE DESIGN VALUES AND

2020 DESIGN VALUES (ppb) AT PROJECTED MAINTENANCE-ONLY RECEPTORS

Monitor ID State County 

2016 

centered 

average 

2016 

centered 

maximum 

2023 

average 

2023 

maximum 2020 

040278011 .................... AZ Yuma ............................ 72.3 74 70.5 72.2 68 

060070007 .................... CA Butte ............................. 76.7 79 68.9 71.0 73 

060090001 .................... CA Calaveras ..................... 77.0 78 70.9 71.9 72 

060371103 .................... CA Los Angeles .................. 73.0 74 70.5 71.5 76 

060430006 .................... CA Mariposa ....................... 75.0 76 70.1 71.0 79 


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123The EPA’s modeling also projects that three 

monitoring sites in the Uintah Basin (i.e., monitor 

490472003 in Uintah County, Utah and monitors 

490130002 and 490137011 in Duchesne County, 

Utah) will have average design values above the 

NAAQS in 2023. However, as described in the 

AQM TSD, the Uinta Basin nonattainment area was 

designated as nonattainment for the 2015 ozone 

NAAQS not because of an ongoing problem with 

summertime ozone (as is usually the case in other 

parts of the country), but instead because it violates 

the ozone NAAQS in winter. The main causes of 

the Uinta Basin’s wintertime ozone are sources 

located at low elevations within the Basin, the 

Basin’s unique topography, and the influence of the 

wintertime meteorologic inversions that keep ozone 

and ozone precursors near the Basin floor and 

restrict air flow in the Basin. Because of the 

localized nature of the ozone problem at these sites 

the EPA has not identified these three monitors as 

receptors in Step 1 of this proposed rule. 

124As part of this technique, ozone formed from 

reactions between biogenic VOC and NOX with 

anthropogenic NOX and VOC are assigned to the 

anthropogenic emissions. 

TABLE V.D–2—AVERAGE AND MAXIMUM 2016-CENTERED AND 2023 BASE CASE 8-HOUR OZONE DESIGN VALUES AND

2020 DESIGN VALUES (ppb) AT PROJECTED MAINTENANCE-ONLY RECEPTORS—Continued 

Monitor ID State County 

2016 

centered 

average 

2016 

centered 

maximum 

2023 

average 

2023 

maximum 2020 

060675003 .................... CA Sacramento .................. 77.3 79 70.2 71.7 70 

060711234 .................... CA San Bernardino ............ 72.3 76 70.6 74.2 76 

061112002 .................... CA Ventura ......................... 77.3 78 70.9 71.6 77 

170310001 .................... IL Cook ............................. 73.0 77 69.6 73.4 75 

170310032 .................... IL Cook ............................. 72.3 75 69.8 72.4 74 

170310076 .................... IL Cook ............................. 72.0 75 69.3 72.1 69 

170314201 .................... IL Cook ............................. 73.3 77 69.9 73.4 77 

170317002 .................... IL Cook ............................. 74.0 77 70.1 73.0 75 

320030075 .................... NV Clark ............................. 75.0 76 70.0 71.0 74 

350130021 .................... NM Dona Ana ..................... 72.7 74 70.9 72.2 78 

350130022 .................... NM Dona Ana ..................... 71.3 74 69.5 72.1 74 

420170012 .................... PA Bucks ............................ 79.3 81 70.7 72.2 74 

480391004 .................... TX Brazoria ........................ 74.7 77 70.1 72.3 73 

481210034 .................... TX Denton .......................... 78.0 80 70.4 72.2 72 

481410037 .................... TX El Paso ......................... 71.3 73 69.6 71.3 76 

482011034 .................... TX Harris ............................ 73.7 75 70.3 71.6 73 

482011035 .................... TX Harris ............................ 71.3 75 68.0 71.6 70 

490450004 .................... UT Tooele ........................... 73.5 74 70.8 71.3 69 

490570002 .................... UT Weber ........................... 73.0 75 70.6 72.5 N/A 

490571003 .................... UT Weber ........................... 73.0 74 70.5 71.5 71 

550590025 .................... WI Kenosha ....................... 73.7 77 69.2 72.3 74 

In total, in the 2023 base case there 

are a total of 111 receptors nationwide 

including 85 nonattainment receptors 

and 26 maintenance-only receptors.123

Of the 85 nonattainment receptors in 

2023, 75 remain nonattainment 

receptors while 8 are projected to 

become maintenance-only receptors and 

2 are projected to be in attainment in 

2026. Of the 26 maintenance-only 

receptors in 2023, 13 are projected to 

remain maintenance-only receptors and 

13 are projected to be in attainment in 

2026. The projected average and 

maximum design values in 2026 for all 

receptors are included in the AQM TSD. 

E. Pollutant Transport From Upwind 

States 

1. Air Quality Modeling To Quantify 

Upwind State Contributions 

This section documents the 

procedures the EPA used to quantify the 

impact of emissions from specific 

upwind states on ozone design values in 

2023 and 2026 for the identified 

downwind nonattainment and 

maintenance receptors. The EPA used 

CAMx photochemical source 

apportionment modeling to quantify the 

impact of emissions in specific upwind 

states on downwind nonattainment and 

maintenance receptors for 8-hour ozone. 

CAMx employs enhanced source 

apportionment techniques that track the 

formation and transport of ozone from 

specific emissions sources and 

calculates the contribution of sources 

and precursors to ozone for individual 

receptor locations. The benefit of the 

photochemical model source 

apportionment technique is that all 

modeled ozone at a given receptor 

location in the modeling domain is 

tracked back to specific sources of 

emissions and boundary conditions to 

fully characterize culpable sources. 

The EPA performed nationwide, statelevel ozone source apportionment 

modeling using the CAMx Ozone 

Source Apportionment Technology/ 

Anthropogenic Precursor Culpability 

Analysis (OSAT/APCA) technique 124 to 

quantify the contribution of 2023 and 

2026 base case NOX and VOC emissions 

from all sources in each state to the 

corresponding projected ozone design 

values in 2023 and 2026 at air quality 

monitoring sites. The CAMx OSAT/ 

APCA model run was performed for the 

period May 1 through September 30 

using the projected future base case 

emissions and 2016 meteorology for this 

time period. As described earlier, in the 

source apportionment modeling the 

Agency tracked (i.e., tagged) the amount 

of ozone formed from anthropogenic 

emissions in each state individually as 

well as the contributions from other 

sources (e.g., natural emissions). 

In the state-by-state source 

apportionment model run, the EPA 

tracked the ozone formed from each of 

the following tags: 

• States—anthropogenic NOX and 

VOC emissions from each state tracked 

individually (emissions from all 

anthropogenic sectors in a given state 

were combined); 

• Biogenics—biogenic NOX and VOC 

emissions domain-wide (i.e., not by 

state); 

• Boundary Concentrations— 

concentrations transported into the air 

quality modeling domain; 

• Tribes—the emissions from those 

tribal lands for which the Agency has 

point source inventory data in the 

2016v1 emissions modeling platform 

(EPA did not model the contributions 

from individual tribes); 


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125Note that a contribution metric value was not 

calculated for any receptor at which there were 

fewer than 5 days with model-predicted MDA8 

ozone concentrations greater than or equal to 60 

ppb in 2023. See the AQM TSD for information on 

those receptors that did not meet this criterion. 126 In order to provide consistency in the 

contributions for 2023 and 2026, the contribution 

metric values for 2026 are based on the 2026 daily 

contributions for the same days that were used to 

calculate the contribution metric values for 2023. 

• Canada and Mexico— 

anthropogenic emissions from sources 

in the portions of Canada and Mexico 

included in the modeling domain (the 

EPA did not model the contributions 

from Canada and Mexico separately); 

• Fires—combined emissions from 

wild and prescribed fires domain-wide 

(i.e., not by state); and 

• Offshore—combined emissions 

from offshore marine vessels and 

offshore drilling platforms. 

The contribution modeling provided 

contributions to ozone from 

anthropogenic NOX and VOC emissions 

in each state, individually. The 

contributions to ozone from chemical 

reactions between biogenic NOX and 

VOC emissions were modeled and 

assigned to the ‘‘biogenic’’ category. The 

contributions from wildfire and 

prescribed fire NOX and VOC emissions 

were modeled and assigned to the 

‘‘fires’’ category. That is, the 

contributions from the ‘‘biogenic’’ and 

‘‘fires’’ categories are not assigned to 

individual states nor are they included 

in the state contributions. 

For the Step 2 analysis, the EPA 

calculated a contribution metric that 

considers the average contribution on 

the 10 highest ozone concentration days 

(i.e., top 10 days) in 2023. This average 

contribution metric is intended to 

provide a reasonable representation of 

the contribution from individual states 

to projected future year design values, 

based on modeled transport patterns 

and other meteorological conditions 

generally associated with modeled high 

ozone concentrations at the receptor. An 

average contribution metric constructed 

in this manner is beneficial since the 

magnitude of the contributions is 

directly related to the magnitude of the 

design value at each site. 

The analytic steps for calculating the 

contribution metric for the 2023 analytic 

year are as follows: 

(1) Calculate the 8-hour average 

contribution from each source tag to 

each monitoring site for the time period 

of the 8-hour daily maximum modeled 

concentrations in 2023; 

(2) Average the contributions and 

average the concentrations for the top 10 

modeled ozone concentration days in 

2023; 

(3) Divide the average contribution by 

the corresponding average concentration 

to obtain a Relative Contribution Factor 

(RCF) for each monitoring site; 

(4) Multiply the 2023 average design 

values by the 2023 RCF at each site to 

produce the average contribution metric 

values in 2023.125

This same approach was applied to 

calculate contribution metric values at 

individual monitoring sites for 2026.126

The resulting contributions from each 

tag to each monitoring site in the U.S. 

for 2023 and 2026 can be found in the 

docket for this proposed rule. 

Additional details on the source 

apportionment modeling and the 

procedures for calculating contributions 

can be found in the AQM TSD. 

The largest contribution from each 

state that is the subject of this rule to 

8-hour ozone nonattainment and 

maintenance receptors in downwind 

states in 2023 and 2026 are provided in 

Table V.E.1–1 and Table V.E.1–2, 

respectively. 

TABLE V.E.1–1—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE

RECEPTORS IN 2023 (ppb) 

Upwind state 

Largest 

contribution 

to downwind 

nonattainment 

receptors 

Largest 

contribution 

to downwind 

maintenanceonly 

receptors 

Alabama ................................................................................................................................................................... 0.88 0.71 

Arizona ..................................................................................................................................................................... 0.40 0.21 

Arkansas .................................................................................................................................................................. 1.00 1.39 

California .................................................................................................................................................................. 34.24 7.44 

Colorado .................................................................................................................................................................. 0.07 0.20 

Connecticut .............................................................................................................................................................. 0.01 0.21 

Delaware .................................................................................................................................................................. 0.53 1.36 

District of Columbia ................................................................................................................................................. 0.04 0.07 

Florida ...................................................................................................................................................................... 0.16 0.15 

Georgia .................................................................................................................................................................... 0.16 0.17 

Idaho ........................................................................................................................................................................ 0.55 0.57 

Illinois ....................................................................................................................................................................... 18.13 18.55 

Indiana ..................................................................................................................................................................... 6.60 7.10 

Iowa ......................................................................................................................................................................... 0.64 0.58 

Kansas ..................................................................................................................................................................... 0.42 0.59 

Kentucky .................................................................................................................................................................. 0.83 0.88 

Louisiana .................................................................................................................................................................. 5.39 7.03 

Maine ....................................................................................................................................................................... 0.01 0.01 

Maryland .................................................................................................................................................................. 1.29 2.40 

Massachusetts ......................................................................................................................................................... 0.30 0.30 

Michigan ................................................................................................................................................................... 1.27 1.67 

Minnesota ................................................................................................................................................................ 0.50 0.97 

Mississippi ................................................................................................................................................................ 1.04 1.14 

Missouri .................................................................................................................................................................... 1.08 1.66 

Montana ................................................................................................................................................................... 0.08 0.11 

Nebraska .................................................................................................................................................................. 0.26 0.36 

Nevada ..................................................................................................................................................................... 0.89 0.58 

New Hampshire ....................................................................................................................................................... 0.10 0.06 

New Jersey .............................................................................................................................................................. 8.85 5.79 


lotter on DSK11XQN23PROD with PROPOSALS2
20072 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

TABLE V.E.1–1—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE

RECEPTORS IN 2023 (ppb)—Continued 

Upwind state 

Largest 

contribution 

to downwind 

nonattainment 

receptors 

Largest 

contribution 

to downwind 

maintenanceonly 

receptors 

New Mexico ............................................................................................................................................................. 0.30 0.13 

New York ................................................................................................................................................................. 16.81 1.80 

North Carolina .......................................................................................................................................................... 0.61 0.33 

North Dakota ............................................................................................................................................................ 0.12 0.37 

Ohio ......................................................................................................................................................................... 1.94 1.88 

Oklahoma ................................................................................................................................................................. 0.57 1.19 

Oregon ..................................................................................................................................................................... 1.10 1.31 

Pennsylvania ............................................................................................................................................................ 6.90 0.51 

Rhode Island ............................................................................................................................................................ 0.04 0.04 

South Carolina ......................................................................................................................................................... 0.19 0.07 

South Dakota ........................................................................................................................................................... 0.05 0.09 

Tennessee ............................................................................................................................................................... 0.60 0.94 

Texas ....................................................................................................................................................................... 1.72 1.81 

Utah ......................................................................................................................................................................... 1.37 0.10 

Vermont ................................................................................................................................................................... 0.02 0.02 

Virginia ..................................................................................................................................................................... 1.77 1.63 

Washington .............................................................................................................................................................. 0.34 0.40 

West Virginia ............................................................................................................................................................ 1.45 1.44 

Wisconsin ................................................................................................................................................................. 0.19 2.61 

Wyoming .................................................................................................................................................................. 0.81 0.19 

TABLE V.E.1–2—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE

RECEPTORS IN 2026 (ppb) 

Upwind state 

Largest 

contribution 

to downwind 

nonattainment 

receptors 

Largest 

contribution 

to downwind 

maintenanceonly 

receptors 

Alabama ................................................................................................................................................................... 0.17 0.48 

Arizona ..................................................................................................................................................................... 0.35 0.23 

Arkansas .................................................................................................................................................................. 0.62 1.30 

California .................................................................................................................................................................. 33.45 4.85 

Colorado .................................................................................................................................................................. 0.05 0.08 

Connecticut .............................................................................................................................................................. 0.01 0.01 

Delaware .................................................................................................................................................................. 0.42 0.52 

District of Columbia ................................................................................................................................................. 0.03 0.04 

Florida ...................................................................................................................................................................... 0.10 0.09 

Georgia .................................................................................................................................................................... 0.14 0.16 

Idaho ........................................................................................................................................................................ 0.48 0.48 

Illinois ....................................................................................................................................................................... 17.81 18.14 

Indiana ..................................................................................................................................................................... 6.43 6.99 

Iowa ......................................................................................................................................................................... 0.57 0.57 

Kansas ..................................................................................................................................................................... 0.40 0.57 

Kentucky .................................................................................................................................................................. 0.80 0.80 

Louisiana .................................................................................................................................................................. 4.25 6.97 

Maine ....................................................................................................................................................................... 0.01 0.01 

Maryland .................................................................................................................................................................. 1.11 1.23 

Massachusetts ......................................................................................................................................................... 0.29 0.14 

Michigan ................................................................................................................................................................... 1.03 1.58 

Minnesota ................................................................................................................................................................ 0.36 0.91 

Mississippi ................................................................................................................................................................ 0.36 0.90 

Missouri .................................................................................................................................................................... 0.98 1.53 

Montana ................................................................................................................................................................... 0.07 0.08 

Nebraska .................................................................................................................................................................. 0.11 0.23 

Nevada ..................................................................................................................................................................... 0.81 0.51 

New Hampshire ....................................................................................................................................................... 0.09 0.02 

New Jersey .............................................................................................................................................................. 8.54 5.47 

New Mexico ............................................................................................................................................................. 0.29 0.23 

New York ................................................................................................................................................................. 16.58 11.29 

North Carolina .......................................................................................................................................................... 0.38 0.54 

North Dakota ............................................................................................................................................................ 0.11 0.34 

Ohio ......................................................................................................................................................................... 1.78 1.83 

Oklahoma ................................................................................................................................................................. 0.54 0.72 


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127August 2018 memo at 4. 

128We 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. 

TABLE V.E.1–2—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE

RECEPTORS IN 2026 (ppb)—Continued 

Upwind state 

Largest 

contribution 

to downwind 

nonattainment 

receptors 

Largest 

contribution 

to downwind 

maintenanceonly 

receptors 

Oregon ..................................................................................................................................................................... 0.98 0.88 

Pennsylvania ............................................................................................................................................................ 6.82 4.74 

Rhode Island ............................................................................................................................................................ 0.04 0.01 

South Carolina ......................................................................................................................................................... 0.15 0.17 

South Dakota ........................................................................................................................................................... 0.03 0.06 

Tennessee ............................................................................................................................................................... 0.25 0.34 

Texas ....................................................................................................................................................................... 1.61 1.70 

Utah ......................................................................................................................................................................... 0.95 1.18 

Vermont ................................................................................................................................................................... 0.02 0.01 

Virginia ..................................................................................................................................................................... 1.14 1.68 

Washington .............................................................................................................................................................. 0.31 0.28 

West Virginia ............................................................................................................................................................ 1.23 1.35 

Wisconsin ................................................................................................................................................................. 0.15 2.44 

Wyoming .................................................................................................................................................................. 0.46 0.80 

2. Application of Contribution 

Screening Threshold 

The EPA evaluated the magnitude of 

the contributions from each upwind 

state to downwind nonattainment and 

maintenance receptors. In Step 2 of the 

interstate transport framework, the EPA 

uses an air quality screening threshold 

to identify upwind states that contribute 

to downwind ozone concentrations in 

amounts sufficient to ‘‘link’’ them to 

these to downwind nonattainment and 

maintenance receptors. The 

contributions from each state to each 

downwind nonattainment or 

maintenance receptor that were used for 

the Step 2 evaluation can be found in 

the AQM TSD. 

The EPA proposes to apply an air 

quality screening threshold of 1 percent 

of the NAAQS, as it has used since the 

CSAPR rulemaking, including in the 

CSAPR Update, the Revised CSAPR 

Update, and numerous actions 

evaluating states’ transport SIP 

submittals. EPA continues to observe 

that the majority of nonattainment and 

maintenance receptors identified at Step 

1 are impacted collectively by 

contributions of ozone transport from 

numerous upwind states. Therefore, 

application of a uniform screening 

threshold allows EPA to identify 

upwind states that share a responsibility 

under the interstate transport provision 

to eliminate their significant 

contribution. 

The EPA recognizes that in 2018 it 

issued a memorandum indicating the 

potential for states to use a higher 

threshold at Step 2 in the development 

of their good neighbor SIP submissions 

where it could be technically justified. 

The August 2018 memorandum stated 

that ‘‘it may be reasonable and 

appropriate’’ for states to rely on an 

alternative 1 ppb threshold at Step 2.127

(The memorandum also indicated that 

any higher alternative threshold, such as 

2 ppb, would likely not be appropriate.) 

Here, the EPA proposes to fulfill its role 

under CAA section 110(c) in 

promulgating FIPs to directly 

implement good neighbor requirements, 

and in this role, the EPA notes that it 

is authorized to exercise discretion in 

making policy determinations such as 

the appropriateness of a particular 

contribution threshold that would 

otherwise have been exercised by states. 

Further, as the EPA has explained in 

several notices proposing transport SIP 

disapprovals, see, e.g., 87 FR 9498 and 

87 FR 9510 (Feb. 22, 2022), its 

experience since the issuance of the 

August 2018 memorandum regarding 

use of alternative thresholds leads the 

Agency to now believe it may not be 

appropriate to continue to attempt to 

recognize alternative contribution 

thresholds at Step 2, either in the 

context of SIPs or FIPs. 

EPA’s experience since 2018 is that 

allowing for alternative Step 2 

thresholds may be impractical or 

otherwise inadvisable for a number of 

additional policy reasons. For a regional 

air pollutant such as ozone, consistency 

in requirements and expectations across 

all states is essential. In the context of 

a FIP proposal (as much as in the 

context of SIP actions), the Agency now 

believes using different thresholds at 

Step 2 with respect to the 2015 ozone 

NAAQS raises substantial policy 

consistency and practical 

implementation concerns.128 The 

availability of different thresholds at 

Step 2 has the potential to result in 

inconsistent application of good 

neighbor obligations. From the 

perspective of ensuring effective 

regional implementation of good 

neighbor obligations, the more 

important analysis is the evaluation of 

the emissions reductions needed, if any, 

to address a state’s significant 

contribution after consideration of a 

multifactor analysis at Step 3, including 

a detailed evaluation that considers air 

quality factors and cost. Where 

alternative thresholds for purposes of 

Step 2 may be ‘‘similar’’ in terms of 

capturing the relative amount of upwind 

contribution (as described in the August 

2018 memorandum), nonetheless, use of 

an alternative threshold would allow 

certain states to avoid further evaluation 

of potential emissions controls while 

other states must proceed to a Step 3 

analysis. This can create significant 

equity and consistency problems among 

states. 

More importantly, in promulgating 

FIPs to address these obligations on a 

nationwide scale, national ozone 

transport policy is not well-served by 

allowing for less stringent thresholds at 

Step 2. The EPA recognized in the 

August 2018 memo that there was some 

similarity in the amount of total upwind 

contribution captured (on a nationwide 

basis) between 1 percent and 1 ppb. 

However, the EPA notes that while this 


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129See August 2018 memo, at 4. 

130The EPA proposed to approve Hawaii’s 2015 

ozone transport SIP on September 28, 2021. See 86 

FR 53571. 

131The EPA approved Alaska’s 2015 ozone 

transport SIP on December 18, 2019. See 84 FR 

69331. 

132See 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. 

133See 81 FR 71991 (October 19, 2016), 82 FR 

9155 (February 3, 2017). 

may be true in some sense, that is 

hardly a compelling basis to move to a 

1 ppb threshold. Indeed, the 1 ppb 

threshold has the disadvantage of losing 

a certain amount of total upwind 

contribution for further evaluation at 

Step 3 (e.g., roughly 7 percent of total 

upwind state contribution was lost 

according to the modeling underlying 

the August 2018 memo; 129 in EPA’s 

updated modeling, the amount lost is 

roughly 5 percent). Considering the core 

statutory objective of ensuring 

elimination of all significant 

contribution to nonattainment or 

interference of the NAAQS in other 

states and the broad, regional nature of 

the collective contribution problem with 

respect to ozone, there does not appear 

to be a compelling policy imperative in 

moving to a 1 ppb threshold. 

Consistency with past interstate 

transport actions such as CSAPR, and 

the CSAPR Update and Revised CSAPR 

Update rulemakings (which used a Step 

2 threshold of 1 percent of the NAAQS 

for two less stringent ozone NAAQS) is 

also important. Continuing to use a 1 

percent of NAAQS approach ensures 

that as the NAAQS are revised and 

made more stringent, an appropriate 

increase in stringency at Step 2 occurs, 

so as to ensure an appropriately larger 

amount of total upwind-state 

contribution is captured for purposes of 

fully addressing interstate transport for 

the more stringent NAAQS. EPA made 

this point when it originally 

promulgated CSAPR to address the 1997 

ozone NAAQS. The Agency continues 

to consider this an important 

consideration for the more stringent 

2015 ozone NAAQS. See 76 FR 48237– 

38. 

Lastly, the Agency does not find it to 

be a good use of limited resources to 

attempt to further justify the use of 

alternative thresholds for certain states 

at Step 2 for purposes of the 2015 ozone 

NAAQS. Therefore, while EPA 

articulated a potential basis for 

recognizing the usefulness of alternative 

Step 2 thresholds (particularly a 1 ppb 

threshold) in the August 2018 

memorandum, EPA’s experience and 

further evaluation since the issuance of 

that memo has revealed substantial 

programmatic and policy difficulties in 

attempting to implement this approach. 

Depending on comment and further 

evaluation of this issue, the EPA may 

determine to rescind the 2018 

memorandum in the future. 

In light of the considerations above, 

EPA proposes using a contribution 

threshold of 0.70 ppb as the 

quantification of 1 percent of the 2015 

ozone NAAQS for purposes of Step 2. 

a. States That Contribute Below the 

Screening Threshold 

Based on EPA’s modeling, the 

contributions from each of the following 

states to nonattainment or maintenanceonly receptors in the 2023 analytic year 

are below the 1% of the NAAQS 

threshold: Arizona, Colorado, 

Connecticut, the District of Columbia, 

Florida, Georgia, Idaho, Iowa, Kansas, 

Maine, Massachusetts, Montana, 

Nebraska, New Hampshire, New 

Mexico, North Carolina, North Dakota, 

Rhode Island, South Carolina, South 

Dakota, Vermont, and Washington. The 

EPA has already approved many of 

these states’ SIP submittals or is in the 

process of taking action to approve 

them. Because the contributions from 

these states to projected downwind air 

quality problems are below the 

screening threshold in the current 

modeling, these states are not within the 

scope of this proposed rule. 

Additionally, the EPA has made 

proposed or final determinations that 

two states outside the modeling domain 

for the air quality modeling analyzed in 

this proposed rulemaking—Hawaii 130

and Alaska 131—do not significantly 

contribute to nonattainment or interfere 

with maintenance of the NAAQS in any 

other state. 

a. States That Contribute at or Above the 

Screening Threshold 

Based on the maximum downwind 

contributions in Table V.E.1–1, the Step 

2 analysis identifies that the following 

22 states contribute at or above the 0.70 

ppb threshold to downwind 

nonattainment receptors in 2023: 

Alabama, Arkansas, California, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oregon, Pennsylvania, 

Texas, Utah, Virginia, West Virginia, 

and Wyoming. Based on the maximum 

downwind contributions in Table 

V.E.1–1, the following 23 states 

contribute at or above the 0.70 ppb 

threshold to downwind maintenanceonly receptors in 2023: Alabama, 

Arkansas, California, Delaware, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New Jersey, New 

York, Ohio, Oklahoma, Oregon, 

Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin. The levels of 

contribution between each of these 

linked upwind states and downwind 

nonattainment receptors and 

maintenance-only receptors are 

provided in the AQM TSD. 

Among the linked states are several 

western states—California, Nevada, 

Oregon, Utah, and Wyoming. While the 

EPA has not previously included action 

on linked western states in its prior 

CSAPR rulemakings, the EPA has 

consistently applied the 4-step 

framework in evaluating good neighbor 

obligations from these states. On a caseby-case basis, the EPA has found in 

some instances with respect to the 2008 

ozone NAAQS that a unique 

consideration has warranted approval of 

a linked western state’s good neighbor 

SIP submittal without concluding that 

additional emissions reductions are 

required at Step 3 of the framework.132

The EPA has also explained in prior 

actions that its air quality modeling is 

reliable for assessing downwind air 

quality problems and ozone transport 

contributions from upwind states 

throughout the nationwide modeling 

domain.133

In EPA’s current analysis, the EPA 

finds that for one linked state— 

Oregon—the same considerations that 

led it to approve another state’s SIP 

submission, Arizona’s, for the 2008 

ozone NAAQS apply to Oregon’s 

circumstances for the 2015 ozone 

NAAQS. As explained in the following 

section, the EPA therefore proposes to 

affirm its prior approval of Oregon’s 

good neighbor SIP submission for the 

2015 ozone NAAQS. For the remaining 

western states included in this proposed 

rule, EPA’s modeling supports a 

conclusion that these states are linked 

above the contribution threshold to 

identified ozone transport receptors in 

other states, and therefore, consistent 

with the treatment of all other states 

within the modeling domain, the EPA 

proposes to proceed to evaluate these 

states for a determination of ‘‘significant 

contribution’’ at Step 3. 

In conclusion, as described above, 

states with contributions that equal or 

exceed 1 percent of the NAAQS to 

either nonattainment or maintenance 

receptors are identified as ‘‘linked’’ at 

Step 2 of the good neighbor framework 

and warrant further analysis for 

significant contribution to 

nonattainment or interference with 


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134Monitors are listed in the AQM TSD included 

in the docket for this rulemaking. While EPA is 

providing information about cumulative upwind 

contribution to the California monitors, the Agency 

does not consider these monitors as ozone transport 

receptors in this proposal. 

135 81 FR 15200 (March 22, 2016) (proposal); 81 

FR 31513 (May 19, 2016) (final rule). 

136 81 FR at 15203. 

137 Id. 

138 Id. 

139See Air Quality Modeling TSDin the docket 

for this action. 

140 81 FR at 15203; 81 FR 31513. 

141See CSAPR, Final Rule, 76 FR 48208 (August 

8, 2011). 

maintenance under Step 3. The EPA 

proposes that the following 27 States are 

linked at Step 2 in 2023: Alabama, 

Arkansas, California, Delaware, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Oregon, Pennsylvania, Tennessee, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming. In addition, 

the EPA proposes that the following 24 

States are linked at Step 2 in 2026: 

Arkansas, California, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Oregon, 

Pennsylvania, Texas, Utah, Virginia, 

West Virginia, Wisconsin, and 

Wyoming. Three states, Alabama, 

Delaware, and Tennessee, that were 

linked in 2023 are not linked in 2026 

because the receptor(s) to which each 

state was linked in 2023 are projected to 

attain by 2026. 

F. Treatment of Certain Receptors in 

California and Implications for Oregon’s 

Good Neighbor Obligations for the 2015 

Ozone NAAQS 

The EPA previously approved 

Oregon’s September 25, 2018 transport 

SIP submittal for the 2015 ozone 

NAAQS on May 17, 2019 (84 FR 22376), 

because in an earlier round of modeling 

Oregon was not projected to contribute 

above 1 percent of the NAAQS to any 

downwind receptors. In EPA’s updated 

modeling, Oregon is linked above the 1 

percent of NAAQS threshold to several 

monitoring sites in California that 

would generally meet EPA’s definition 

of nonattainment or maintenance 

‘‘receptors’’ at Step 1.134 However, 

EPA’s analysis of the nature of the air 

quality problem at these monitoring 

sites leads EPA to propose a 

determination that these monitoring 

sites should not be treated as receptors 

for purposes of determining interstate 

transport obligations of upwind states 

under CAA section 110(a)(2)(D)(i)(I). 

EPA reaches this conclusion at Step 1 of 

its four-step framework. 

The EPA previously made a similar 

assessment of the nature of certain other 

monitoring sites in California in 

approving Arizona’s 2008 ozone 

NAAQS transport SIP submittal.135

There, the EPA noted that a ‘‘factor 

[. . .] relevant to determining the nature 

of a projected receptor’s interstate 

transport problem is the magnitude of 

ozone attributable to transport from all 

upwind states collectively contributing 

to the air quality problem.’’ 136 The EPA 

observed that only one upwind state 

(Arizona) was linked above 1 percent of 

the 2008 ozone NAAQS to the two 

relevant monitoring sites in California, 

and the cumulative ozone contribution 

from all upwind states to those sites was 

2.5 percent and 4.4 percent of the total 

ozone, respectively. The EPA 

determined the size of those cumulative 

upwind contributions was ‘‘negligible, 

particularly when compared to the 

relatively large contributions from 

upwind states in the East or in certain 

other areas of the West.’’ 137 In that 

action, the EPA concluded the two 

California sites to which Arizona was 

linked should not be treated as receptors 

for the purposes of determining Good 

Neighbor obligations for the 2008 ozone 

NAAQS.138

The EPA proposes to make a similar 

finding for the monitoring sites in 

California otherwise projected in its 

current modeling to be ‘‘receptors’’ for 

the 2015 ozone NAAQS and to which 

Oregon is linked. The highest percent of 

the total cumulative upwind ozone 

contribution to any of these sites is 2.8 

percent.139 This is lower than the largest 

transport contribution relative to total 

ozone at the California sites identified 

in EPA’s approval of Arizona’s 2008 

ozone transport SIP (4.4 percent).140

Further, as was the case for the sites in 

California analyzed in EPA’s Arizona 

action, the identified sites in California 

each have only one upwind state 

contributing above 1 percent of the 

NAAQS to them (Oregon). These 

monitoring sites in California are 

overwhelmingly impacted by in-state 

emissions to a degree not comparable 

with any other identified nonattainment 

or maintenance-only receptors in the 

country. 

The EPA proposes to find that these 

monitoring sites should not be 

considered receptors for the purpose of 

assessing 2015 ozone NAAQS interstate 

transport obligations. The EPA is not 

proposing a different contribution 

threshold at Step 2 for Western states or 

receptors, nor does the EPA reach its 

conclusion based on any evaluation at 

Step 3 of emissions reduction 

opportunities in Oregon. 

As a consequence of this proposed 

finding, the EPA continues to find that 

ozone-precursor emissions from Oregon 

do not significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in any 

downwind state, because the total 

collective upwind state ozone 

contribution to the California 

monitoring sites is extremely low 

compared to the air quality problems 

typically addressed under the good 

neighbor provision. Therefore, the EPA 

is not proposing any change in this 

action to its prior approval of Oregon’s 

SIP. The EPA is not proposing any new 

FIP requirements and is not proposing 

to require reductions from new or 

existing EGU or non-EGU sources in 

Oregon in this action. If, however, EPA 

were not to finalize this proposed 

approach, then EPA anticipates that it 

would apply the same control strategies 

in Oregon as applied in all other linked 

upwind states, as discussed in Sections 

VI and VII of this proposed rule. EPA 

requests public comment on its 

approach to characterizing the nature of 

the interstate transport problem at the 

California monitoring sites at issue and 

the consequent approach to assessing 

Oregon’s good neighbor obligations. 

VI. Quantifying Upwind-State NOX

Emissions Reduction Potential To 

Reduce Interstate Ozone Transport for 

the 2015 Ozone NAAQS 

A. The Multi-Factor Test for 

Determining Significant Contribution 

This section describes EPA’s 

methodology at Step 3 of the 4-step 

framework for identifying upwind 

emissions that constitute ‘‘significant’’ 

contribution for the states subject to this 

proposed rule and focuses on the 26 

states with FIP requirements identified 

in the sections above. Following the 

existing framework as applied in all of 

the prior CSAPR rulemakings, EPA’s 

assessment of linked upwind state 

emissions is based primarily on analysis 

of several alternative levels of NOX

emissions control stringency applied 

uniformly across all of the linked states. 

The analysis includes assessment of 

non-EGU stationary sources in addition 

to EGU sources in the linked upwind 

states. 

The EPA applies a multi-factor test— 

the same multi-factor test that was used 

in CSAPR, the CSAPR Update, and the 

Revised CSAPR Update 141—to evaluate 

increasing levels of uniform NOX

control stringency. The multi-factor test, 

which is central to EPA’s Step 3 


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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. 

There are four stages in developing 

the multi-factor test: (1) Identify levels 

of uniform NOX control stringency; (2) 

evaluate potential NOX emissions 

reductions associated with each 

identified level of uniform control 

stringency; (3) assess air quality 

improvements at downwind receptors 

for each level of uniform control 

stringency; and (4) select a level of 

control stringency considering the 

identified cost, available NOX emissions 

reductions, and downwind air quality 

impacts, while also ensuring that 

emissions reductions do not 

unnecessarily over-control relative to 

the contribution threshold or downwind 

air quality. 

As mentioned in Section IV.A.2 of 

this proposed rule, commenters on 

previous ozone transport rules have 

suggested that the EPA should regulate 

VOCs as an ozone precursor. For this 

proposed rule, the EPA examined the 

results of the contribution modeling 

performed for this rule to identify the 

portion of the ozone contribution 

attributable to anthropogenic NOX

emissions versus VOC emissions from 

each linked upwind state to each 

downwind receptor. Of the total 

upwind-downwind linkages in 2023, 

the contributions from NOX emissions 

comprise 80 percent or more of the total 

anthropogenic contribution at the vast 

majority of linkages (136 out of 140 

total). Across all receptors, the 

contribution from NOX emissions ranges 

from 77 percent to 99 percent of the 

total anthropogenic contribution. This 

review of the portion of the ozone 

contribution attributable to 

anthropogenic NOX emissions versus 

VOC emissions from each linked 

upwind state leads the Agency to 

conclude that the vast majority of the 

downwind air quality areas addressed 

by the proposed rule under are 

primarily NOX-limited, rather than 

VOC-limited. Therefore, the EPA is 

proposing to determine that the 

regulation of VOCs as an ozone 

precursor is not necessary to eliminate 

significant contribution of ozone 

transport to downwind areas in this 

proposed rule. The remainder of this 

section focuses on EPA’s strategy for 

reducing regional-scale transport of 

ozone by targeting NOX emissions from 

stationary sources to achieve the most 

effective reductions of ozone transport 

over the geography of the affected 

downwind areas. 

For both EGUs and non-EGUs, Section 

VI.B of this proposed rule describes the 

available NOX emissions controls that 

the EPA evaluated for this proposed rule 

and their representative cost levels (in 

2016$). Section VI.C of this proposed 

rule discusses EPA’s application of that 

information to assess emissions 

reduction potential of the identified 

control stringencies. Finally, Section 

VI.D of this proposed rule describes 

EPA’s assessment of associated air 

quality impacts and EPA’s subsequent 

identification of appropriate control 

stringencies considering the key 

relevant factors (cost, available 

emissions reductions, and downwind 

air quality impacts). 

This multi-factor approach is 

consistent with EPA’s approach in prior 

transport actions, such as CSAPR. In 

addition, as was evaluated in the 

CSAPR Update and Revised CSAPR 

Update, the EPA evaluated possible 

over-control by examining whether an 

upwind state is linked solely to 

downwind air quality problems that 

could have been resolved at a lesser 

threshold of control stringency and 

whether an upwind state could reduce 

its emissions below the 1 percent air 

quality contribution threshold at a lesser 

threshold of control stringency. This 

analysis is described in Section VI.D of 

this proposed rule. 

Finally, while the EPA has evaluated 

potential emissions reductions from 

non-EGU sources in prior rules, this is 

the first action for which the EPA is 

proposing non-EGU emissions 

reductions within the context of its 4- 

step interstate transport framework. The 

EPA applies its multi-factor test to nonEGUs and independently evaluates nonEGU industries in a consistent but 

parallel track to its Step 3 assessment 

for EGUs. This is consistent with the 

parallel assessment approach taken for 

EGUs and non-EGUs in the Revised 

CSAPR Update. Following the 

conclusions of the EGU and non-EGU 

multi-factor tests, the identified 

reductions for EGUs and non-EGUs are 

combined and collectively analyzed to 

assess their effects on downwind air 

quality and whether the rule achieves a 

full remedy to ‘‘significant 

contribution’’ while avoiding overcontrol. 

In order to ensure that this rule 

implements a full remedy for the 

elimination of significant contribution 

from upwind states, the EPA has 

reviewed available information on all 

major industrial source sectors in the 

upwind states. This analysis leads the 

EPA to propose that both EGUs and 

certain large sources in several specific 

industrial categories should be 

evaluated for emissions control 

opportunities. As discussed in the 

sections that follow, the EPA proposes 

that for both EGUs and the selected nonEGU source categories, there are 

impactful emissions reduction 

opportunities available at reasonable 

cost-effectiveness thresholds. As in the 

Revised CSAPR Update, the EPA 

examines EGUs and non-EGUs in this 

section on consistent but distinct, 

parallel tracks due to differences 

stemming from the unique 

characteristics of the power sector 

compared to other industrial source 

categories. Since the NOX SIP Call, 

EGUs have consistently been regulated 

under ozone transport rules. These units 

operate in a coordinated manner across 

a highly interconnected electrical grid. 

Their configuration and emissions 

control strategies are relatively 

homogenous, and their emissions levels 

and emissions control opportunities are 

generally very well understood due to 

longstanding monitoring and datareporting requirements. Non-EGU 

sources, by contrast, are relatively 

heterogeneous, even within a single 

industrial category, and have far greater 

variation in existing emissions control 

requirements, emissions levels, and 

technologies to reduce emissions. In 

general, despite these differences, the 

information available for this proposal 

indicates that both EGUs and certain 

non-EGU categories have available costeffective NOX emissions reduction 

opportunities at relatively 

commensurate cost per ton levels, and 

these emissions reductions will make a 

meaningful improvement in air quality 


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142The EPA recognizes that mechanisms exist 

under title I of the CAA that allow for the regulation 

of the use and operation of mobile sources to reduce 

ozone-precursor emissions. These include motor 

vehicle inspection and maintenance (I/M) 

programs, gasoline vapor recovery, clean-fuel 

vehicle programs, transportation control programs, 

and vehicle miles traveled programs. See, e.g., CAA 

sections 182(b)(3), 182(b)(4), 182(c)(3), 182(c)(4), 

182(c)(5), 182(d)(1), 182(e)(3), and 182(e)(4). The 

EPA views these programs as most effective and 

appropriate in the context of the planning 

requirements applicable to designated 

nonattainment areas. 

143See ‘‘Ozone Season Data 2018 vs. 2019’’ and 

‘‘Coal-fired Characteristics and Controls’’ at https:// 

www.epa.gov/airmarkets/power-plant-datahighlights#OzoneSeason. 

144The CSAPR Update estimated $1,400 per ton 

as a representative cost of turning on idled SCR 

controls. EPA used the same costing methodology 

Continued 

at the downwind receptors. Section 

VI.B.2 of this proposed rule describes 

EPA’s process for selecting specific Tier 

I and Tier II non-EGU source categories 

included in this proposed rulemaking. 

The EPA notes that its Step 3 analysis 

does not assess emissions reduction 

opportunities from mobile sources. The 

EPA continues to believe that title II of 

the CAA provides the primary authority 

and process for reducing ozoneprecursor pollutants from mobile 

sources. EPA’s federal mobile source 

programs have delivered and are 

projected to continue to deliver 

substantial nationwide reductions in 

both VOCs and NOX emissions; these 

reductions are factored into the 

Agency’s assessment of air quality and 

contributions at Steps 1 and 2. Further, 

states are generally preempted from 

regulating new vehicles and engines 

with certain exceptions, and therefore a 

question exists regarding EPA’s 

authority to address such emissions 

when regulating in place of the states 

under CAA section 110(c). See generally 

CAA sections 209, 177. See also 86 FR 

23099. As noted earlier, the EPA 

accounted for mobile source emissions 

reductions resulting from other federally 

enforceable regulatory programs in the 

development of emissions inventories 

used to support analysis for this 

proposed rulemaking, and the EPA does 

not evaluate any mobile source control 

measures in its Step 3 evaluation in this 

proposal.142 For further discussion of 

EPA’s existing and ongoing mobile 

source measures, see Section VI.B.4 of 

this proposed rule. 

B. Identifying Control Stringency Levels 

1. EGU NOX Mitigation Strategies 

In identifying levels of uniform 

control stringency for EGUs, the EPA 

assessed the same NOX emissions 

controls that the Agency analyzed in the 

CSAPR Update and the Revised CSAPR 

Update, all of which are considered to 

be widely available in this sector: (1) 

Fully operating existing SCR, including 

both optimizing NOX removal by 

existing operational SCRs and turning 

on and optimizing existing idled SCRs; 

(2) installing state-of-the-art NOX

combustion controls; (3) fully operating 

existing SNCRs, including both 

optimizing NOX removal by existing 

operational SNCRs and turning on and 

optimizing existing idled SNCRs; (4) 

installing new SNCRs; (5) installing new 

SCRs; and (6) generation shifting (i.e., 

emission reductions anticipated to 

occur from generation shifting from 

higher to lower emitting units at each of 

these stringency levels). For the reasons 

explained in the EGU NOX Mitigation 

Strategies Proposed Rule TSD included 

in the docket for this proposed rule, the 

EPA determined that for the regional, 

multi-state scale of this rulemaking, 

only EGU NOX emissions controls 1, 3, 

and 6 are possible for the 2023 ozone 

season (fully operating existing SCRs 

and SNCRs, and associated generation 

shifting). The EPA finds that it is not 

possible to install state-of-the-art NOX

combustion controls by the 2023 ozone 

season on a regional scale for Group 3 

states not covered under the Revised 

CSAPR Rule. The EPA also determined 

that state-of-the-art NOX combustion 

controls at EGUs are available by the 

beginning of the 2024 ozone season. All 

cost values discussed below for EGUs 

are in 2016 dollars. 

a. Optimizing Existing SCRs 

Optimizing (i.e., turning on idled or 

improving operation of partially 

operating) existing SCRs can 

substantially reduce EGU NOX

emissions quickly, using investments 

that have already been made in 

pollution control technologies. With the 

promulgation of the CSAPR Update and 

the Revised CSAPR Update, most 

operators in the covered states improved 

their SCR performance and have 

continued to maintain that level of 

improved operation. However, this 

optimized SCR performance was not 

universal and not always sustained. 

Between 2017 and 2020, as the CSAPR 

Update ozone-season NOX allowance 

price declined, NOX emissions rates at 

some SCR-controlled EGUs increased. 

For example, power sector data from 

2019 revealed that, in some cases, 

operating units had SCR controls that 

had been idled or were operating 

partially, and therefore suggested that 

there remained emissions reduction 

potential through optimization.143 The 

EPA determined that optimizing all of 

these remaining SCRs in the 12 linked 

states for the Revised CSAPR Update 

was a readily available approach for 

EGUs to reduce NOX emissions. This 

emissions reduction measure is 

currently available at EGUs across the 

broader geography affected in this 

proposed rulemaking (including in 

states not previously affected by the 

Revised CSAPR Update). The EPA thus 

proposes that SCR optimization, of both 

idled and partially operating controls, is 

a viable mitigation strategy for the 2023 

ozone season. 

The EPA estimates a representative 

marginal cost of optimizing SCR 

controls to be approximately $1,600 per 

ton, consistent with its estimation in the 

Revised CSAPR Update for this 

technology. EPA’s EGU NOX Mitigation 

Strategies Proposed Rule TSD for this 

rule describes a range of cost estimates 

for this technology noting that the costs 

are frequently lower than—and for the 

majority of EGUs, significantly lower 

than—this representative marginal cost. 

While the costs of optimizing existing, 

operational SCRs include only variable 

costs, the cost of optimizing SCR units 

that are currently idled considers both 

variable and fixed costs of returning the 

control into service. Variable and fixed 

costs include labor, maintenance and 

repair, parasitic load, and ammonia or 

urea for use as a NOX reduction reagent 

in SCR systems. Depending on a unit’s 

control operating status, the 

representative cost at the 90th percentile 

unit (among the relevant fleet of coal 

units with SCR covered in this 

rulemaking) ranges between $900 and 

$1,700 per ton. The EPA performed an 

in-depth cost assessment for all coalfired units with SCRs and found that for 

the subset of SCRs that are already 

partially operating, the cost of 

optimizing is often much lower than 

$1,600 per ton and is often under $900 

per ton. The EPA anticipates the vast 

majority of realized cost for compliance 

with this strategy to be better reflected 

by the $900 per ton end of that range 

(reflecting the 90th percentile of EGUs 

optimizing SCRs that are already 

partially operating) because this 

circumstance is considerably more 

common than EGUs that have ceased 

operating their SCR. EPA’s analysis of 

this emissions control is informed by 

the latest engineering modeling 

equations used in EPA’s IPM platform. 

These cost and performance equations 

were recently updated in the summer of 

2021. The description and development 

of the equations are documented in EGU 

NOX Mitigation Strategies Proposed 

Rule TSD and accompanying 

documents.144 They are also 


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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). 

145The EPA notes that updating the inventory of 

units to reflect recent retirements and most recent 

year data (e.g., 2009–2021) would provide a lower 

value of 0.071 lb/mmBtu. This value is lower than 

the 0.08 pounds per million British thermal units 

(lb/mmBtu) assessed in the Revised CSAPR Update 

as it reflects 2020 data and also excludes the SCR 

performance of since retired coal units with SCRs. 

However, 2020 was an outlier year (related to 

pandemic impacts on the electric grid). 

Additionally, a unit’s retirement does not obviate 

the usefulness of its data for assessing technology 

performance. Consequently, EPA is proposing the 

same value of 0.08 lb/mmBtu identified at the time 

of the final Revised CSAPR Update Rule. 

146 In the 22-state CSAPR Update region, 2005 

EGU NOX emissions data suggest that 125 EGUs 

operated SCR systems in the summer ozone season 

while idling these controls for the remaining 7 nonozone season months of the year. Units with SCR 

were identified as those with 2005 ozone season 

average NOX rates that were less than 0.12 lbs/ 

mmBtu and 2005 average non-ozone season NOX

emissions rates that exceeded 0.12 lbs/mmBtu and 

where the average non-ozone season NOX rate was 

more than double the ozone season rate. 

implemented in an interactive 

spreadsheet tool called the Retrofit Cost 

Analyzer and applied to all units in the 

fleet. These materials are available in 

the docket for this proposal. 

The EPA is using the same 

methodology to identify SCR 

performance as it did in the Revised 

CSAPR Update. To estimate EGU NOX

reduction potential from optimizing, the 

EPA considers the difference between 

the non-optimized NOX emissions rates 

and an achievable operating and 

optimized SCR NOX emissions rate. To 

determine this rate, EPA evaluated 

nationwide coal-fired EGU NOX ozone 

season emissions data from 2009 

through 2019 and calculated an average 

NOX ozone season emissions rate across 

the fleet of coal-fired EGUs with SCR for 

each of these eleven years. The EPA 

found it prudent to not consider the 

lowest or second-lowest ozone season 

NOX emissions rates, which may reflect 

SCR systems that have all new 

components (e.g., new layers of 

catalyst). Data from these systems are 

potentially not representative of ongoing 

achievable NOX emissions rates 

considering broken-in components and 

routine maintenance schedules. To 

identify the potential reductions from 

SCR optimization in this proposed rule, 

the EPA followed the same methodology 

as the Revised CSAPR Update. 

Considering the emissions data over the 

full time period from 2009–2019 data 

results in a third-best rate of 0.079 

pounds NOX per million British thermal 

units (lb/mmBtu).145 Therefore, 

consistent with the Revised CSAPR 

Update, where EPA identified 0.08 lb/ 

mmBtu as a reasonable level of 

performance for units with optimized 

SCR, the EPA proposes a rate of 0.08 lb/ 

mmBtu as the optimized rate for this 

rule. The EPA notes that half of the 

SCR-controlled EGUs achieved a NOX

emissions rate of 0.064 lbs/mmBtu or 

less over their third-best entire ozone 

season. Moreover, for the SCRcontrolled 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 gasfired 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 combinedcycle units (for which the EPA 

determined that a 0.012 lb/mmBtu 

emissions rate reflected SCR 

optimization). 

The EPA evaluated the feasibility of 

optimizing idled SCRs for the 2023 

ozone season. Based on industry past 

practice, the EPA determined that idled 

controls can be restored to operation 

quickly (i.e., in less than 2 months). 

This timeframe is informed by many 

electric utilities’ previous long-standing 

practice of utilizing SCRs to reduce EGU 

NOX emissions during the ozone season 

while putting the systems into 

protective lay-up during the non-ozone 

season months. For example, this was 

the long-standing practice of many 

EGUs that used SCR systems for 

compliance with the NOX Budget 

Trading Program. It was quite typical for 

SCRs to be turned off following the 

September 30 end of the ozone season 

control period. These controls would 

then be put into protective lay-up for 

several months of non-use before being 

returned to operation by May 1 of the 

following ozone season.146 Therefore, 

the EPA believes that optimization of 

existing SCRs is possible for the portion 

of the 2023 ozone season covered under 

this proposed rule. 

The vast majority of SCR-controlled 

units (nationwide and in the 25 linked 

states for which EPA is issuing a FIP for 

EGUs) are already partially operating 

these controls during the ozone season 

based on reported 2021 emissions rates. 

Existing SCRs operating at partial 

capacity still provide functioning, 

maintained systems that may only 

require an increased chemical reagent 

feed rate (i.e., ammonia or urea) up to 

their design potential and catalyst 

maintenance for mitigating NOX

emissions; such units may require 

increased frequency or quantity of 

deliveries, which can be accomplished 

within a few weeks. In many cases, 

EGUs with SCR have historically 

achieved more efficient NOX removal 

rates than their current performance and 

can therefore simply revert to earlier 

operation and maintenance plans that 

achieved demonstrably better SCR 

performance. 

In the 12 states subject to this control 

stringency in the Revised CSAPR 

Update, the EPA observed significant 

immediate-term improvements in SCR 

performance in the first ozone season 

following finalization of that rule, as 

evidenced in particular by the sharp 

drop in emissions rate at Miami Fort 

unit 7 (see EGU NOX Mitigation 

Strategies Proposed Rule TSD). Such 

empirical data further illustrates the 

viability of this mitigation strategy for 

the 2023 control period in response to 

this rule. 

b. Installing State-of-the-Art NOX

Combustion Controls 

The EPA estimates that the 

representative cost of installing state-ofthe-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-theVerDate Sep<11>2014 20:07 Apr 05, 2022 Jkt 256001 PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 E:\FR\FM\06APP2.SGM 06APP2

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147 Details of EPA’s assessment of state-of-the-art 

NOX combustion controls are provided in the EGU 

NOX Mitigation Strategies Proposed Rule TSD. 

148The 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. 

149EPA–HQ–OAR–2015–0500–0093. 

150https://www.epa.gov/airmarkets/nationalelectric-energy-data-system-needs-v6. 

art combustion control technology. As 

described in the Revised CSAPR 

Update, the Agency updated its NOX

emissions rates for upgrading existing 

combustion controls to state-of-the-art 

combustion control. The EPA is 

maintaining its determination that NOX

emissions rates of 0.146 to 0.199 lbs/ 

mmBtu can be achieved on average 

depending on the unit’s boiler 

configuration,147 and, once installed, 

reduce NOX emissions at all times of 

EGU operation. 

These assumptions are consistent 

with the Revised CSAPR Update and 

they are further discussed in the EGU 

NOX Mitigation Strategies Proposed 

Rule TSD. In particular, the EPA 

proposes to apply the 0.199 lb/mmBtu 

emissions rate assumption for all unit 

types, consistent with its determination 

in the Revised CSAPR Update. The 

average emissions rate assumption 

derived from EPA’s analysis would be 

0.199 lb/mmBtu for combustion controls 

on dry bottom wall fired units and 0.146 

lb/mmBtu for tangentially fired units. 

However, stakeholders have provided 

detailed analysis of how other unit 

considerations, such as coal rank, can 

result in large deviations from what has 

been historically demonstrated with this 

combustion control technology. Based 

on this and EPA’s review of historical 

performance data for tangentially-fired 

units by coal rank with state-of-the-art 

combustion controls, the EPA 

determined in the final Revised CSAPR 

Update that it was appropriate to use 

the 0.199 lb/mmBtu rate for both 

tangentially and wall-fired units when 

estimating reduction potential for units 

with combustion control upgrade 

potential. 

The EPA proposes to continue that 

approach in this action. Many of the 

likely impacted units burn bituminous 

coal, and the 0.146 lb/mmBtu 

nationwide average for tangentiallyfired (inclusive of subbituminous units) 

appears to be below the demonstrated 

emissions rate of state-of-the-art 

combustion controls for bituminous coal 

units of this boiler type. Therefore, 

EPA’s assumption of 0.199 lb/mmBtu 

for combustion controls is robust to 

current and future coal choice at a unit. 

In promulgating CSAPR, the EPA 

examined the feasibility of installing 

combustion controls, and found that 

industry had demonstrated ability to 

install state-of-the-art LNB controls on a 

large unit (800 MW) in under six 

months when including the preinstallation phases (design, order 

placement, fabrication, and delivery).148

In prior rules, the EPA has documented 

its own assessment of combustion 

control timing installation as well as 

evaluated comments it received 

regarding installation of combustion 

controls from the Institute of Clean Air 

Companies.149 Those comments 

provided information on the equipment 

and typical installation time frame for 

new combustion controls, accounting 

for all steps. Commenters noted that it 

generally takes between 6–8 months on 

a typical boiler—covering the time 

through bid evaluation through start-up 

of the technology. The deployment 

schedule is repeated here as: 

• 4–8 weeks—bid evaluation and 

negotiation 

• 4–6 weeks—engineering and 

completion of engineering drawings 

• 2 weeks—drawing review and 

approval from user 

• 10–12 weeks—fabrication of 

equipment and shipping to end user 

site 

• 2–3 weeks—installation at end user 

site 

• 1 week—commissioning and start-up 

of technology 

Given the above timeframe of 

approximately 6 to 8 months to 

complete combustion control 

installation in the region, the EPA is 

proposing to determine that installation 

of state-of-the-art combustion controls is 

a readily available approach for EGUs to 

reduce NOX emissions by the start of the 

2024 ozone season. More details on 

these analyses can be found in the EGU 

NOX Mitigation Strategies Proposed 

Rule TSD. 

The cost of installing state-of-the-art 

combustion controls per ton of NOX

reduced is dependent on the 

combustion control type and unit type. 

The EPA estimates the cost per ton of 

state-of-the-art combustion controls to 

be $400 per ton to $1,200 per ton of 

NOX removed using a representative 

capacity factor of 85 percent. This cost 

fits well within EPA’s representative 

cost threshold observed for SCR 

optimization and combustion controls 

(of $1,600 per ton) which would 

accommodate combustion control 

upgrade even under scenarios where a 

lower capacity factor is assumed. See 

the EGU NOX Mitigation Strategies 

Proposed Rule TSD for additional 

details. 

c. Optimizing Already Operating SNCRs 

or Turning on Idled Existing SNCRs 

Optimizing already operating SNCRs 

or turning on idled existing SNCRs can 

also reduce EGU NOX emissions 

quickly, using investments in pollution 

control technologies that have already 

been made. Compared to no postcombustion controls on a unit, SNCRs 

can achieve a 25 percent reduction on 

average in EGU NOX emissions (with 

sufficient reagent). They are less capital 

intensive but less efficient at NOX

removal than SCRs. These controls are 

in use to some degree across the U.S. 

power sector. In the 25 linked states 

identified in this proposed rule with 

identified EGU reductions in their 

proposed FIP, approximately 11 percent 

of coal-fired EGU capacity is equipped 

with SNCR.150 Recent power sector data 

suggest that, in some cases, SNCR 

controls have been operating less in 

2021 relative to performance in prior 

years. 

The EPA determined that optimizing 

already operating SNCRs or turning on 

idled SNCRs is an available approach 

for EGUs to reduce NOX emissions, has 

similar implementation timing to 

restarting idled SCR controls (less than 

2 months for a given unit), and therefore 

could be implemented in time for the 

2023 ozone season. The EPA is 

proposing implementation of this 

emissions control technology beginning 

in the 2023 ozone season. 

Using an updated data assessment 

using the Retrofit Cost Analyzer 

described in the EGU NOX Mitigation 

Strategies Proposed TSD, the EPA 

estimates a representative cost of 

optimizing SNCR ranging from 

approximately $1,800 per ton (for 

partially operating SNCRs) to $3,900 per 

ton (for idled SNCRs). For existing 

SNCRs that have been idled, unit 

operators may need to restart payment 

of some fixed and variable operating 

costs including labor, maintenance and 

repair, parasitic load, and ammonia or 

urea. The EPA determined that the 

majority of units with existing SNCR 

optimization potential were already 

partially operating their controls. 

Therefore, the EPA proposes a 

representative cost of $1,800 per ton for 

SNCR optimization as this value best 

reflects the circumstances of the 

majority of the affected EGUs with 

SNCR. 


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151See EGU NOX Mitigation Strategies Proposed 

Rule TSD for additional discussion. 

152A month-by-month evaluation of SNCR 

installation is discussed in EPA’s NOX Mitigation 

Strategies Proposed Rule TSD and in EPA’s 

‘‘Engineering and Economic Factors Affecting the 

Installation of Control Technologies for 

Multipollutant Strategies’’. The analysis in this 

exhibit estimates the installation period from 

contract award as within a 10–13-month timeframe. 

The exhibit also indicates a 16-month timeframe 

from start to finish, inclusive of pre-contract award 

steps of the engineering assessment of technologies 

and bid request development. The timeframe cited 

for installation of SNCR at an individual source in 

this action is consistent with this more complete 

timeframe estimated by the analysis in the exhibit. 

153 IPM Model-Updates to Cost and Performance 

for APC Technologies. SCR Cost Development 

Methodology for Coal-fired Boilers. February 2022. 

d. Installing New SNCRs 

Like existing SNCRs, new SNCR 

retrofit is also available to power plants 

and can achieve a 25% NOX reduction 

on average. The EPA evaluated potential 

emissions reductions and associated 

costs from retrofitting EGUs with new 

SNCR post-combustion controls at 

steam units lacking such controls. New 

SNCR technology provides owners with 

a relatively less capital-intensive option 

for reducing NOX emissions compared 

to new SCR technology, albeit at the 

expense of higher operating costs on a 

per-ton basis and less total emissions 

reduction potential. SNCR is more 

widely observed on relatively smaller 

coal units given its low capital/variable 

cost ratio. The average capacity of a coal 

unit with SNCR is half the size of the 

average capacity of coal unit with 

SCR.151 Given these observations, the 

EPA identifies this technology as an 

emissions reduction measure for coal 

units less than 100 MW lacking postcombustion NOX control technology. As 

described in the EGU NOX Mitigation 

Strategies Proposed Rule TSD, the EPA 

estimated that $6,700 per ton reflects a 

representative SNCR retrofit cost level 

for a majority of these units. 

SNCR installations generally have 

shorter project installation timeframes 

relative to other post-combustion 

controls. The time for engineering 

review, contract award, fabrication, 

delivery, and hookup is as little as 16 

months including pre-contract award 

steps for an individual power plant 

installing controls on more than one 

boiler. This timeframe would mean the 

control would be available for the start 

of the 2024 or 2025 ozone season (i.e., 

calculating 16 months from when this 

proposal is finalized). However, SNCR 

retrofits have less pollution reduction 

potential than alternative postcombustion controls such as SCRs. The 

EPA is not identifying SNCR technology 

as a strategy for larger steam units due 

to this lower removal efficiency and the 

empirical evidence of existing sources 

preferring the more efficient SCRs. Even 

for those smaller units less than 100 

MWs identified as potential candidates 

for this technology, the EPA does not 

want to preclude those units from 

pursuing more advanced pollution 

controls. Therefore, the EPA also 

considers the point in time when all 

types of post-combustion control 

installation could be achieved—i.e., by 

the 2026 ozone season. SNCR 

installation share similar 

implementation steps with and also 

need to account for the same regional 

factors as SCR installations.152

Therefore, while the EPA is determining 

that at least 16 months would be needed 

to complete all necessary steps of SNCR 

development and installation at the 

EGUs not currently equipped with 

SNCRs in the 25 states linked to 

downwind receptors in this proposed 

rule, the EPA notes that the Agency 

evaluated SNCR as a post-combustion 

control technology collectively with 

SCR and estimated installation timing 

considerations of 36 months. EPA 

believes its proposed collective timing 

considerations for post-combustion 

control retrofit (SNCR and SCR) are 

practicable given that the preferable 

capital-intensive investment retrofit 

decision would be highly unit-specific 

and subject to a unit’s compliance 

strategy choices with respect to multiple 

regulatory requirements. 

Nonetheless, the EPA is requesting 

comment on whether post-combustion 

control timing assumptions (SCR and 

SNCR) should be decoupled, which 

would result in the EPA using the 16- 

month time frame specific to SNCR 

installation to estimate the first year in 

which these reductions are available. 

The EPA is only identifying this 

technology for units less than 100 MW 

(a size at which units rarely implement 

SCR retrofit technology). In effect, 

decoupling these timing assumptions 

would move the reductions associated 

with this control stringency from 

beginning in the 2026 ozone season to 

beginning in the 2024 or 2025 ozone 

season (depending on when this 

proposal is finalized). This would 

impact approximately 1,000 tons of 

identified reduction potential related to 

SNCR retrofit. 

e. Installing New SCRs 

Selective Catalytic Reduction (SCR) 

controls already exist on approximately 

60% of the coal fleet in the linked states 

that would be subject to a FIP in this 

proposed rulemaking. Nearly every 

pulverized coal unit larger than 100 MW 

built in the last 30 years has installed 

this control, which is generally required 

for Best Available Control Technology 

(BACT) purposes. Other than circulating 

fluidized bed coal units which can 

achieve a comparably low emissions 

rate without this technology, the EPA 

identifies this emissions reduction 

measure for coal steam units greater 

than or equal to 100 MW. SCR is widely 

available for existing coal units of this 

size and can provide significant 

emissions reduction potential, with 

removal efficiencies of up to 90 percent. 

The EPA limited its consideration of 

SCR technology to steam units greater 

than or equal to 100 MW. The costs for 

retrofitting a plant smaller than 100 MW 

with SCR increase rapidly due to a lack 

of economy of scale.153

The amount of time needed to retrofit 

an EGU with new SCR extends beyond 

the 2023 ozone season. The EPA 

proposes that a strategy of retrofitting 

new SCR on a fleetwide, regional scale 

is available by, but no earlier than, the 

2026 ozone season. Similar to the SNCR 

retrofits discussed above, the EPA 

evaluated potential emissions 

reductions and associated costs from 

this control technology, as well as the 

impacts and need for this emissions 

control strategy, at the earliest point in 

time when their installation could be 

achieved. In the past, the EPA has found 

the amount of time to retrofit a single 

EGU with new SCR, depending on the 

regulatory program under which such 

control may be required, may vary 

between approximately 2 and 4 years 

depending on site-specific engineering 

considerations and on the number of 

installations being considered. This 

includes steps for engineering review, 

construction permit, operating permit, 

and control technology installation 

(including fabrication, pre hookup, 

control hookup, and testing). EPA’s 

assessment of installation procedures 

suggests as little as 21 months may be 

needed for a single SCR at an individual 

plant and 36 months at a single plant 

with multiple boilers. EPA’s assessment 

of units with SCR retrofit potential 

indicate the majority fall into this first 

classification, i.e., a single SCR at a 

power plant. Given that some of the 

assumed SCR retrofit potential occurs at 

plants with multiple units identified 

with retrofit potential, and given the 

total volume of SCR retrofit capacity 

being implemented across the region, 

The EPA is proposing 36 months as an 

appropriate time frame to accommodate 

both instances as well as scheduling 

necessities attributable to the regionalscale nature of the program. 


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154See, e.g., CSAPR Close-Out, 83 FR 65878, 

65895 (December 21, 2018). See also Final Report: 

Engineering and Economic Factors Affecting the 

Installation of Control Technologies for 

Multipollutant Strategies, EPA–600/R–02/073 (Oct. 

2002), available at https://nepis.epa.gov/Adobe/ 

PDF/P1001G0O.pdf. 155As 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. 

156This cost estimate is representative of coal 

units lacking any post-combustion control. A subset 

of units within the universe of coal sources with 

SCR retrofit potential, but that have an existing 

SNCR technology in place would have a weighted 

average cost that falls above this level, but still cost 

effective. See the EGU NOX Mitigation Strategies 

Proposed Rule TSD for more discussion. 

157The 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. 

Further, the EPA notes that it has 

previously determined in the context of 

ozone transport that regional scale 

implementation of SCRs at numerous 

EGUs is achievable in 36 months. See 63 

FR 57356, 57447–50 (October. 27, 1998). 

The EPA has at times also found up to 

39–48 months to be an appropriate 

installation timeframe for regionwide 

actions when the EPA is evaluating 

multiple installations at multiple 

locations.154 However, as discussed in 

greater detail in Section VII.A in this 

proposed rule, the EPA now recognizes 

that the Wisconsin decision invalidated 

the standard under which the EPA had 

been evaluating appropriate compliance 

timeframes for purposes of assessing 

interstate transport under the good 

neighbor provision when the Agency 

had concluded a 39–48 month 

timeframe to install SCR was 

appropriate. 

The Agency examined the cost for 

retrofitting a coal unit with new SCR 

technology, which typically attains 

controlled NOX rates of 0.05 lbs/mmBtu 

or less. These updates are further 

discussed in the EGU NOX Mitigation 

Strategies Proposed Rule TSD.155 Based 

on the characteristics of coal units of 

100 MW or greater capacity that do not 

have post-combustion NOX control 

technology, the EPA estimated a 

weighted-average representative SCR 

cost of $11,000 per ton.156

The 0.05 lb/mmBtu emission rate 

performance assumption for new SCR 

retrofits is supported by historical data 

and third party independent review by 

pollution control engineering and 

consulting firms. The EPA first 

examined unit-level emission rate data 

for coal-fired units that had a relatively 

recent SCR installation (within the last 

10 years). These SCR retrofits reflect the 

most recent vintage of the pollution 

control technology applied to the power 

sector and are representative of new 

SCR retrofit capability. Although 

regulatory requirements or economic 

incentives were not necessarily in place 

during this time period for these SCRs 

to operate at their full potential, the EPA 

found that half of these units had still 

demonstrated a seasonal emission rate 

of 0.05 lb/mmBtu or lower and 78 

percent had demonstrated this rate on a 

monthly basis. The best performing 10 

percent of these SCRs were 

demonstrating seasonal emission rates 

of 0.036 lb/mmBtu during this time. 

While the EPA identified the 0.05 lb/ 

mmBtu performance assumption 

consistent with historical data, these 

performance levels are also informed 

and consistent with the Agency’s IPM 

modeling assumptions used for more 

than a decade. These modeling 

assumptions are based on input from 

leading engineering and pollution 

control consulting entities. Most 

recently, these data assumptions were 

affirmed and updated in the summer of 

2021 and included in the docket for this 

rulemaking. The EPA relies on a global 

firm providing engineering, 

construction management, and 

consulting services for power and 

energy with expertise in grid 

modernization, renewable energy, 

energy storage, nuclear power, and 

fossil fuels. Their familiarity with stateof-the art pollution controls at power 

plants derives from experience 

providing comprehensive project 

services—from consulting, design, and 

implementation to construction 

management, commissioning, and 

operations/maintenance. This review 

and update supported the 0.05 lb/ 

mmBtu performance assumption as a 

representative emission rate for new 

SCR across coal types. 

The EPA performed an assessment for 

oil/gas steam units in which it evaluated 

the nationwide performance of those 

units with SCR technology. For these 

units, the EPA tabulated EGU NOX

ozone season emissions data from 2009 

through 2021 and calculated an average 

NOX ozone season emissions rate across 

the fleet of oil- and gas-fired EGUs with 

SCR for each of these years. The EPA 

identified the third lowest year which 

yielded an SCR performance rate of 0.03 

lb/mmBtu as representative of 

performance for this retrofit technology 

applied to this type of EGU. Next, the 

EPA evaluated the emissions and 

operational characteristics for the 

existing oil/gas steam fleet lacking SCR 

technology. EPA’s analysis indicated 

that the majority of reduction potential 

(approximately 76 percent) from these 

units occurred at units greater than or 

equal to 100 MW and that were emitting 

more than 150 tons per ozone season 

(i.e., approximately 1 ton per day). 

Moreover, the cost of reductions for 

units falling below these criteria 

increased significantly. Therefore, the 

EPA identified the portion of the oil/gas 

steam fleet meeting this criteria as 

representative of the SCR retrofit 

reduction potential.157 For this segment 

of the oil/gas steam units lacking postcombustion NOX control technology, the 

EPA estimated a weighted-average 

representative SCR cost of $7,700 per 

ton. 

f. Generation Shifting 

Finally, EPA evaluates emissions 

reduction potential from generation 

shifting across the representative dollar 

per ton levels estimated for the 

emissions controls considered above. As 

the cost of emitting NOX increases, it 

becomes increasingly cost-effective for 

units with lower NOX rates to increase 

generation, while units with higher NOX

rates reduce generation. Because the 

cost of generation is unit-specific, this 

generation shifting occurs incrementally 

on a continuum. Consequently, there is 

more generation shifting at higher cost 

NOX-control levels. 

It is reasonable for the EPA to 

quantify and include the emissions 

reduction potential from generation 

shifting at cost levels that are 

representative of the emissions control 

technologies evaluated in the multifactor analysis, because all EGUs that 

would be regulated by this proposed 

rule participate in highly coordinated, 

interconnected systems where 

generation shifting will inevitably occur 

in response to pollution control 

requirements. If the EPA did not 

account for such emissions reduction 

potential in its analysis at Step 3, 

seeking emissions reductions from 

pollution control measures at higherNOX-emitting EGUs would still 

incentivize generation shifting toward 

lower-NOX-emitting EGUs when sources 

comply under the remedy mechanism 

established in Step 4, and the 

corresponding reductions in emissions 

achieved through such generation 

shifting would potentially substitute for 

some of the emissions reductions 

intended through control operation and 

installation, potentially lessening the 

implementation of those mitigation 

strategies. Generation shifting treatment 

and results are discussed in greater 

detail in the EGU NOX Mitigation 

Strategies Proposed TSD and the Ozone 

Transport Policy Analysis Proposed 

Rule TSD. 


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158The EPA discussed its legal authority for and 

the technical viability of generation shifting as a 

method of emissions reduction under the good 

neighbor provision in the CSAPR Update. See 

especially 81 FR 74504, 74545–47; see also CSAPR 

Update Response to Comment Document at 546– 

550 (legal authority); id. 528–533 (technical 

feasibility). See Final Revised CSAPR Update, 86 

FR 23096–97. 

159The EPA also noted in the CSAPR Update, 

‘‘Interpreting the Good Neighbor Provision to be 

sufficiently broad to authorize reliance on 

generation shifting is also consistent with the 

legislative history for the 1970 CAA Amendments. 

The Senate Report stated that to achieve the 

NAAQS, ‘[g]reater use of natural gas for electric 

power generation may be required,’ S. Rep. No. 91– 

1196 at 2.’’ 81 FR 74545 n.141. 

160The feasibility of the timetable for emissions 

reductions from both EGUs and non-EGUs is further 

addressed in Section VII.A of this proposed rule. 

161The EPA used the Revised CSAPR Update air 

quality modeling for this screening assessment 

because the air quality modeling for this proposed 

rule was not completed in time to support the 

assessment. 

The EPA notes that its treatment of 

generation shifting here is consistent 

with the prior CSAPR rulemakings and 

is grounded on the same statutory 

authority. See, e.g., 76 FR 48208, 48280 

(August 8, 2011). As the EPA explained 

in the CSAPR Update: 158

The good neighbor provision requires state 

and federal plans implementing its 

requirements to ‘‘prohibit[ ] . . . any source 

or other type of emissions activity within the 

State from emitting any air pollutant in 

amounts which will’’ significantly contribute 

to nonattainment or interfere with 

maintenance of the NAAQS in any other 

state. CAA section 110(a)(2)(D)(i)(I) 

(emphasis added). . . . [T]he statute does 

not limit the EPA’s authority under the good 

neighbor provision to basing regulation only 

to control strategies for individual sources. 

The statute authorizes the state or EPA in 

promulgating a plan to prohibit emissions 

from ‘‘any source or other type of emissions 

activity within the State’’ that contributes (as 

determined by EPA) to the interstate 

transport problem with respect to a particular 

NAAQS. This broad statutory language 

shows that Congress was directing the states 

and the EPA to address a wide range of 

entities and activities that may be responsible 

for downwind emissions. However, this 

provision is silent as to the type of emissions 

reduction measures that the states and the 

EPA may consider in establishing emissions 

reduction requirements, and it does not limit 

those measures to individual source 

controls. . . . The EPA reasonably interprets 

this provision to authorize consideration of a 

wide range of measures to reduce emissions 

from sources, which is consistent with the 

broad scope of this provision, as noted 

immediately above. 

81 FR 74545.159 The EPA continued to 

apply this same understanding in the 

Revised CSAPR Update. See 86 FR 

23054, 23095–97 (April 30, 2021); see 

also 85 FR 68964, 68992–93 (October 

30, 2020). 

The EPA requests comment on the 

suite of mitigation technologies for 

EGUs described earlier and assessed in 

the determination of significant 

contribution. The EPA requests 

comment on the assumed performance 

or emissions rate of the technology, the 

representative cost, and the timing for 

installation.160 Additionally, the EPA 

requests comment on whether other 

EGU ozone-season NOX Mitigation 

technologies should be required to 

eliminate significant contribution. For 

instance, the EGU NOX Mitigation 

Strategies Proposed Rule TSD discusses 

certain mitigation technologies that 

have been applied to ‘‘peaking’’ units 

(small, low capacity factor gas 

combustion turbines often only 

operating during periods of peak 

demand). To the extent that any of these 

sources meet the applicability 

requirements and are covered in the 

Group 3 trading program under this 

proposed rulemaking, they would have 

an incentive to reduce emissions 

consistent with the ozone season NOX

allowance price. The EPA has not 

identified determinative evidence that 

there are additional meaningful, costeffective upwind reductions from these 

emission controls that are not already 

being addressed by state rules. EPA’s 

analysis discussed in the EGU NOX

Mitigation Strategies Proposed Rule 

TSD highlights that there are 32 units 

emitting more than 10 tons per year on 

average for the 2019–2021 ozone 

seasons and lacking combustion 

controls or more advanced controls 

(totaling approximately 1,000 tons of 

ozone season NOX emissions in 2021). 

Some of the units in the limited 

inventory are subject to state 

requirements delivering additional 

reductions by 2023. Moreover, the EPA 

analysis suggested $25,000–$30,000 per 

ton estimates for dry low NOX burners 

or ultra-low NOX burners at these units, 

and over $100,000 per ton for SCR 

retrofit at some combustion turbines. 

Therefore, the EPA is not proposing any 

additional reductions from new controls 

for inclusion in its combustion control 

or retrofit technology breakpoints. 

Although the EPA is not proposing a 

mitigation technology for this type of 

unit, it requests comment on the 

potential emissions reductions and cost 

from such sources in covered states that 

do not currently have mitigation 

requirements for such sources. 

2. Non-EGU NOX Mitigation Strategies 

a. Determining Non-EGU NOX

Reduction Potential 

The number of different industries 

and emissions unit categories and types, 

as well as the total number of emissions 

units that comprise the universe of nonEGU sources, makes it challenging to 

define a single method to identify 

appropriate control technologies, 

measures, or strategies and resulting 

impactful emissions reductions. 

Because of these challenges, the EPA 

adopted a different approach for 

assessing non-EGU NOX emissions 

reduction potential than the approach 

for EGUs described in the preceding 

section. To assess emissions reduction 

potential from non-EGUs, the EPA first 

performed a screening assessment to 

identify those industries that could have 

the greatest air quality impact at 

downwind receptors. This was followed 

by an assessment estimating annual 

NOX emissions reduction potential at 

specific cost thresholds for each of the 

most impactful industries. Next, the 

EPA estimated the reductions in ozone 

concentrations resulting from the 

emissions reductions for each industry 

in each of the 27 linked upwind states. 

As described later, the results indicate 

that the most impactful industries fall 

into two tiers based on the estimated 

reductions in ozone concentrations 

associated with the NOX emissions 

reductions. 

The Agency incorporated air quality 

information as a first step in an 

analytical framework to help determine 

potentially impactful industries to focus 

on for further assessing potential 

controls, emissions reduction potential, 

air quality improvements, and costs. 

The EPA developed the analytical 

framework using inputs from the air 

quality modeling for the Revised CSAPR 

Update for 2023,161 as well as the 

projected 2023 annual emissions 

inventory from the 2016v2 emissions 

platform that was used for the air 

quality modeling for this proposed rule. 

Additional information on the analytical 

framework is presented in the Non-EGU 

Screening Assessment memorandum 

available in the docket. 

Using the Revised CSAPR Update 

modeling for 2023, the EPA identified 

upwind states linked to downwind 

nonattainment or maintenance receptors 

using the 1 percent of the NAAQS 

threshold criterion, which is 0.7 ppb (1 

percent of a 70 ppb NAAQS). In 2023 

there were 27 linked states for the 2015 

ozone NAAQS: Alabama, Arkansas, 

California, Delaware, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, Nevada, New Jersey, New 

York, Ohio, Oklahoma, Oregon, 

Pennsylvania, Tennessee, Texas, Utah, 

Virginia, West Virginia, Wisconsin, and 

Wyoming. 


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162The calibration factors are receptor-specific 

factors. For the Revised CSAPR Update, the 

calibration factors were generated using 2016 base 

case and 2023 base case air quality model runs. 

These receptor-level ppb/ton factors are discussed 

in the Ozone Transport Policy Analysis Final Rule 

TSD found here: https://www.epa.gov/sites/default/ 

files/2021-03/documents/ozone_transport_policy_

analysis_final_rule_tsd_0.pdf. 

163 In the non-EGU emissions reduction 

assessment prepared for the Revised Cross State Air 

Pollution Rule Update (https://

www.regulations.gov/document/EPA-HQ-OAR2020-0272-0014), The EPA reviewed emissions 

units with >150 tpy of NOX emissions. In this 

assessment, EPA broadened the scope to include 

emissions units with greater than or equal to 100 

tpy of NOX emissions. 

164The EPA chose to include in the Non-EGU 

NOX reduction potential analysis those industries 

that contribute at least 0.01 ppb to a downwind 

receptor in order to focus the analysis on the most 

impactful industries. The 0.01 criterion is based on 

an analysis of the distribution and relative 

magnitude of contributions from 41 industries, as 

identified in the Non-EGU Screening Assessment 

memorandum. From this analysis the EPA 

determined that 0.01 ppb provides a meaningful 

conservative breakpoint for screening out nonimpactful industries from the Non-EGU analysis in 

this proposed rule. Details on this analysis that 

provides the basis for using 0.01 ppb can be found 

in the Non-EGU Screening Assessment 

memorandum. 

165Further information on CoST can be found at 

the following link: https://www.epa.gov/economicand-cost-analysis-air-pollution-regulations/costanalysis-modelstools-air-pollution. 

166The CMDB is available at the following link: 

https://www.epa.gov/economic-and-cost-analysisair-pollution-regulations/cost-analysis-modelstoolsair-pollution. 

167The maximum emissions reduction algorithm 

assigns to each source the single measure (if a 

measure is available for the source) that provides 

the maximum reduction to the target pollutant. For 

more information, see the CoST User’s Guide 

available at the following link: https://

www.cmascenter.org/cost/documentation/3.7/ 

CoST%20User’s%20Guide/. 

168 Known controls are well-demonstrated control 

devices and methods that are currently used in 

practice in many industries. Known controls do not 

include cutting edge or emerging pollution control 

technologies. 

To analyze non-EGU emissions units, 

the EPA aggregated the underlying 

projected 2023 emissions inventory data 

into industries defined by 4-digit 

NAICS. Then for linked states, the EPA 

followed the 2-step process below: 

Step 1—The EPA identified industries 

whose potentially controllable 

emissions have the greatest ppb impact 

on downwind air quality, and 

Step 2—The EPA determined which 

of the most impactful industries and 

emissions units had the most emissions 

reductions that would make meaningful 

air quality improvements at the 

downwind receptors at a marginal cost 

threshold the EPA determined using 

underlying control device efficiency and 

cost information. 

To estimate the contributions by 

industry, defined by 4-digit NAICS, at 

each downwind receptor the EPA used 

the 2023 state-receptor specific Revised 

CSAPR Update ppb/ton values and the 

Revised CSAPR Update calibration 

factors used in the air quality 

assessment tool (AQAT) for control 

analyses in 2023.162 The EPA focused 

on assessing emissions units that emit 

greater than 100 tons per year (tpy) of 

NOX.163 By limiting the focus to 

potentially controllable emissions, wellcontrolled sources that still emit greater 

than 100 tpy are excluded. Instead, the 

focus is on uncontrolled sources or 

sources that could be better controlled 

at a reasonable cost. As a result, 

reductions from any industry identified 

by this process are more likely to be 

achievable and to lead to air quality 

improvements. 

From this information, the EPA 

prepared a summary with the estimated 

total, maximum, and average 

contributions from each industry and 

the number of receptors with 

contributions greater than or equal to 

0.01 ppb from each industry.164 The 

EPA used this information to identify 

breakpoints in the data to determine 

which industries to focus on for the next 

steps in its analysis, as described in the 

Non-EGU Screening Assessment 

memorandum. 

A review of the maximum 

contribution data indicated that the EPA 

should focus the assessment of NOX

reduction potential and cost primarily 

on four industries. These industries 

each (1) have a maximum contribution 

to any one receptor of greater than 0.10 

ppb and (2) contribute greater than or 

equal to 0.01 ppb to at least 10 

receptors. The four industries identified 

below comprise the ‘‘Tier 1’’ non-EGU 

industries. 

• Pipeline Transportation of Natural 

Gas 

• Cement and Concrete Product 

Manufacturing 

• Iron and Steel Mills and Ferroalloy 

Manufacturing 

• Glass and Glass Product 

Manufacturing 

In addition to these industries, the 

maximum contribution data suggests 

including five additional industries as a 

second tier in the assessment. These 

industries each either have (1) a 

maximum contribution to any one 

receptor greater than or equal to 0.10 

ppb but contribute greater than or equal 

to 0.01 ppb to fewer than 10 receptors, 

or (2) a maximum contribution less than 

0.10 ppb but contribute greater than or 

equal to 0.01 ppb to at least 10 

receptors. The five industries identified 

below comprise the ‘‘Tier 2’’ non-EGU 

industries. 

• Basic Chemical Manufacturing 

• Petroleum and Coal Products 

Manufacturing 

• Metal Ore Mining 

• Lime and Gypsum Product 

Manufacturing 

• Pulp, Paper, and Paperboard Mills 

For additional discussion of the 

contribution information, see Appendix 

A of the Non-EGU Screening 

Assessment memorandum included in 

the docket for this proposed rulemaking. 

Next, to identify an annual cost 

threshold for evaluating potential 

emissions reductions in the Tier 1 and 

Tier 2 industries, the EPA used the 

Control Strategy Tool (CoST),165 the 

Control Measures Database (CMDB),166

and the projected 2023 emissions 

inventory to prepare a listing of 

potential control measures, and costs, 

applied to non-EGU emissions units in 

the projected 2023 emissions inventory. 

Using these data, the EPA plotted curves 

for Tier 1 industries, Tier 2 industries, 

Tier 1 and 2 industries, and all 

industries at $500 per ton increments. 

Figure 1 on page 4 of the Non-EGU 

Screening Assessment memorandum, 

which is available in the docket for this 

proposed rulemaking, indicates there is 

a ‘‘knee in the curve’’ at approximately 

$7,500 per ton (all non-EGU cost 

estimates in the assessment and 

presented in the rest of this section are 

in 2016 dollars). The EPA used this 

marginal cost threshold to further assess 

potential control strategies, estimated 

emissions reductions, air quality 

improvements, and costs from the 

potentially impactful industries. Note 

that controls and related emissions 

reductions are available at several 

estimated cost levels up to the $7,500 

per ton threshold. (These costs do not 

include monitoring, recordkeeping, 

reporting, or testing costs.) 

Next, using the marginal cost 

threshold of $7,500 per ton, to estimate 

emissions reductions and costs the EPA 

processed the CoST run using the 

maximum emissions reduction 

algorithm,167 with known controls.168

The EPA identified controls for nonEGU emissions units in the Tier 1 and 

Tier 2 industries that cost up to $7,500 

per ton. The EPA then calculated air 

quality impacts associated with the 

estimated reductions for the 27 linked 

states in 2023 using the following steps. 

1. The EPA binned the estimated 

reductions by 4-digit NAICS code into 

the Tier 1 and Tier 2 industries. 

2. The EPA used the 2023 statereceptor specific Revised CSAPR 

Update ppb/ton values and the Revised 

CSAPR Update calibration factors used 

in the AQAT for control analyses in 

2023. The EPA multiplied the estimated 


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169The EPA used the 2023fj non-EGU point 

source inventory files from the 2016v2 emissions 

platform. 

170Maryland, Missouri, Nevada, and Wyoming 

did not have boilers with >100 tpy NOX emissions. 

171For the impactful boiler assessment, the 

estimated air quality contributions and 

improvements were not based on modeling of 

individual emissions units or emissions source 

sectors. The air quality estimates were derived by 

using the 2023 state/receptor specific Revised 

CSAPR Update ppb/ton values and the Revised 

CSAPR Update calibration factors used in AQAT. 

The results indicate a level of precision not 

supported by the underlying air quality modeling. 

The results were intended to provide an indication 

of the relative impact across sources. 

172Final Technical Support Document (TSD) for 

the Final Cross-State Air Pollution Rule for the 2008 

Ozone NAAQS, Assessment of Non-EGU NOX

Emissions Controls, Cost of Controls, and Time for 

Compliance Final TSD (‘‘CSAPR Update Non-EGU 

TSD’’), August 2016, available at https://

www.epa.gov/csapr/assessment-non-egu-NOXemission-controls-cost-controls-and-timecompliance-final-tsd. 

173The non-EGU screening assessment is not 

intended to be, nor take the place of, a unit-specific 

detailed engineering analysis that evaluates the 

feasibility of retrofits for the emissions units, 

potential controls, and related costs. For more 

detailed discussion of these issues, see Section 

VII.C of this proposed rule and the Non-EGU 

Sectors TSD included in the docket. 

174The EPA determined that the 2019 inventory 

was appropriate because it provided a more 

accurate prediction of potential near-term emissions 

reductions. See the Non-EGU Screening Assessment 

memorandum, available in the docket, for a 

discussion of the challenges associated with using 

the projected 2023 emissions inventory. 

non-EGU reductions by the ppb/ton 

values and by the receptor-specific 

calibration factor to estimate the ppb 

impacts from these emissions 

reductions. 

Next, because boilers represent the 

majority emissions units in the Tier 2 

industries for which there were controls 

that cost up to $7,500 per ton, the EPA 

further targeted emissions reductions 

and air quality improvements in Tier 2 

industries by identifying potentially 

impactful industrial, commercial, and 

institutional (ICI) boilers. To identify 

potentially impactful boilers, using the 

projected 2023 emissions inventory in 

the linked upwind states, the EPA 

identified a universe of boilers with 

greater than 100 tpy NOX emissions that 

had contributions at downwind 

receptors.169 170 The EPA refined the 

universe of boilers to a subset of 

impactful boilers by sequentially 

applying the three criteria below to each 

boiler. This approach is similar to the 

overall analytical framework and was 

tailored for application to individual 

boilers.171

• Criterion 1—Estimated maximum 

air quality contribution at an individual 

receptor of greater than or equal to 

0.0025 ppb or estimated total 

contribution across downwind receptors 

of greater than or equal to 0.01 ppb. 

• Criterion 2—Controls that cost up to 

$7,500 per ton. 

• Criterion 3—Estimated maximum 

air quality improvement at an 

individual receptor of greater than or 

equal to 0.001 ppb. 

Lastly, the EPA updated its analytical 

framework to the 2026 analytic year by 

which the EPA is proposing non-EGU 

controls be installed across the Tier 1 

and Tier 2 industries and various 

emissions unit types. The EPA 

concluded, based on the most recent 

information available from the CSAPR 

Update Non-EGU TSD,172 that controls 

on all of the non-EGU emissions units 

cannot be installed by the 2023 ozone 

season. The EPA prepared the non-EGU 

screening assessment for the year 2026 

by generally applying the analytical 

framework detailed above, with some 

modifications. The updated screening 

assessment results for 2026 are 

discussed in Section VI.C.2 173 of this 

proposed rule. Specifically, the EPA 

• Retained the impactful industries 

identified in Tier 1 and Tier 2, the 

$7,500 cost per ton threshold, and the 

methodology for identifying impactful 

boilers; 

• Modified the framework to address 

challenges associated with using the 

projected 2023 emissions inventory by 

using the 2019 emissions inventory; 174

and 

• Updated the air quality modeling 

data by using the most recent air quality 

modeling data for this proposal for the 

analytic year 2026. 

3. Other Stationary Sources NOX

Mitigation Strategies 

As part of its analysis for this 

proposed rule, the EPA also reviewed 

whether NOX mitigation strategies for 

any other stationary sources may be 

appropriate. In this section, the EPA 

discusses three classes of units that have 

historically been excluded from our 

interstate air transport programs: (1) 

Units less than or equal to 25 MW, (2) 

solid waste incineration units, and (3) 

cogeneration units. EPA’s initial 

assessment does not lead it to propose 

inclusion of the units less than or equal 

to 25 MW, but the EPA is requesting 

comment on any particular units within 

this category that may offer costeffective reduction potential. The EPA is 

also taking comment on and considering 

whether to include emissions 

limitations for solid waste incineration 

units (many of which are less than 25 

MW) in a final rule, as discussed later. 

For cogeneration units previously 

exempted from EGU emissions budgets 

established through ozone interstate 

transport rules, the EPA has not 

identified a basis for inclusion in this 

proposal. 

The EPA has not historically 

identified substantial emissions 

reduction or air quality gains from 

corresponding reductions from these 

segments of units and has therefore not 

considered inclusion of these segments 

of stationary sources in its federal 

programs for interstate transport. 

However, given the need to 

implement a full remedy to address 

interstate transport, the more stringent 

2015 ozone NAAQS of 70 ppb, and the 

extended period of time for which the 

EPA projects upwind contribution to 

persistent nonattainment and 

maintenance problems, the EPA is 

requesting comment on whether sources 

within these three segments—units 

serving a generator equal or smaller than 

25 MW, cogeneration units, and solid 

waste incineration units—could merit 

inclusion within EPA’s proposed NOX

mitigation strategy in this rule. 

Specifically, the EPA requests comment 

on available NOX mitigation 

technologies, NOX emissions rate 

performance, total potentially available 

NOX reductions, installation timing, 

cost, air quality impacts, source-specific 

information, and any other information 

that could inform a control 

determination specific to these three 

types of units. The EPA provides an 

assessment of these three segments, 

their emissions control opportunities, 

and potential air quality benefits below. 

Additional considerations are further 

discussed in the EGU NOX Mitigation 

Strategies Proposed Rule TSD. 

a. Units Less Than or Equal to 25 MW 

The EPA has historically not included 

control requirements for emissions for 

units less than or equal to 25 MW for 

three primary reasons: Low potential 

reductions, relatively high cost per ton 

of reduction, and high monitoring and 

other compliance burdens. In the 

January 11, 1993, Acid Rain permitting 

rule, the EPA provided for a conditional 

exemption from the emissions 

reduction, emitting, and emissions 

monitoring requirements of the Acid 

Rain Program for new units having a 

nameplate capacity of 25 MWe or less 

that burn fuels with a sulfur content no 

greater than 0.05% by weight, because 

of the de minimis nature of their 

potential SO2, CO2 and NOX emissions. 

See 63 FR 57484. The NOX SIP Call 

identified these as Small Point Sources. 

For the purposes of that rulemaking, the 

EPA considered electricity generating 

boilers and turbines serving a generator 

25 MWe or less, to be small point 

sources. The EPA noted that the 

collective emissions from small sources 


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175Preliminary estimate based on representative 

coal units with starting NOX rate of 0.2 lb/mmBtu, 

10,000 BTU/kwh, and assuming 80 percent 

reduction. 

176 ‘‘AP–42, Fifth Edition Compilation of Air 

Pollutant Emissions Factors, Volume 1: Stationary 

Point and Area Sources’’, available at: https://

www.epa.gov/air-emissions-factors-andquantification/ap-42-compilation-air-emissionsfactors. 

177 ‘‘2018 Directory of Waste to Energy Facilities’’; 

Energy Recovery Council. 

178The NOX permit limits for the Montgomery 

County facility and the Virginia facilities can be 

found within the OTC’s Municipal Waste 

Combustor Workgroup Report included within the 

Docket for this proposed rule. 

were relatively small and the 

administrative burden to the states and 

regulated entities of controlling such 

sources was likely to be considerable. 

As a result, the rule did not assume 

reductions from those sources in state 

emissions budgets requirements (63 FR 

57402). Similar size thresholds have 

been incorporated in subsequent 

transport programs such as CAIR and 

CSAPR. As these sources were not 

identified as having cost-effective 

reductions and so were not included in 

those programs, they were also 

exempted from certain reporting 

requirements and the data for these 

sources is, therefore, not of the same 

caliber as that of covered larger sources. 

EPA’s preliminary survey of current 

data, compared to this initial 

justification, does not appear to offer a 

compelling reason to depart from this 

past practice by requiring emission 

reductions from these small EGU 

sources as part of this rule. For instance, 

as explained in the EGU NOX Mitigation 

Strategies Proposed Rule TSD, EPA has 

evaluated the costs of SCR retrofits at 

small EGUs using its Retrofit Cost 

Analyzer and found that such controls 

become markedly less cost-effective at 

lower levels of generating capacity. This 

analysis concluded that, after 

controlling for all other unit 

characteristics, the dollar per ton cost 

for a SCR retrofit increases by about a 

factor of 2.5 when moving from a 500 

MW to a 10 MW unit, and a factor of 

8 when moving to a 1 MW unit.175

Moreover, the EPA estimates that under 

6% of nationwide EGU emissions come 

from units less than 25 MW and not 

covered by current applicability criteria 

due to this size exemption threshold. 

Therefore, the EPA is not proposing to 

require any emissions reductions from 

these units, but the EPA requests 

comment on whether there are any costeffective reductions and corresponding 

air quality benefits to nonattainment or 

maintenance receptors from any units 

within this segment. 

b. Municipal Solid Waste Units 

The EPA seeks comment on whether 

NOX emissions reductions should be 

sought from municipal solid waste 

combustor units (MWCs) to address 

interstate ozone transport. As noted 

below, MWCs emit substantial amounts 

of NOX, and some states have required 

emissions limits for these facilities that 

are more stringent than the federal 

requirements contained within EPA’s 

new source performance standard 

(NSPS) for this industry. These more 

stringent limits, if applied broadly to the 

26 states included in this proposed FIP 

action, would create an additional 

means of reducing NOX emissions. 

MWCs burn garbage and other nonhazardous solid material using a variety 

of combustion techniques. Section 2.1, 

Refuse Combustion, of the EPA 

emissions factor reference document 

AP–42 176 contains a description of the 

seven different combustion process 

technologies most commonly used in 

the industry. A copy of Section 2.1 of 

AP–42 is included within the Docket for 

this proposed rule. These seven 

combustion processes are as follows: 

Mass burn waterwall, mass burn rotary 

waterwall, mass burn refractory wall, 

refuse-derived fuel-fired, fluidized bed, 

modular starved air, and modular excess 

air. Section 2.1 of AP–42 contains 

detailed process descriptions of each of 

these MWC processes. During the 

combustion process, a number of 

pollutants are produced, including NOX, 

which forms through oxidation of 

nitrogen in the waste and from fixation 

of nitrogen in the air used to burn the 

waste. NOX emissions from MWCs are 

typically released through tall stacks 

which enables the emissions to be 

transported long distances. 

Most MWCs are cogeneration facilities 

that recover heat from the combustion 

process to power a turbine to produce 

electricity. According to a 2018 report 

from the Energy Recovery Council,177 72 

of the 75 operating MWC facilities in the 

U.S. produce electricity from heat 

captured from the combustion process. 

The electrical output of MWCs is 

relatively small compared to the EGUs 

that will be regulated per the proposed 

requirements of Section VII.B of this 

proposal, with most MWCs having an 

electrical output capacity of less than 25 

MW. The Non-EGU Sectors TSD located 

in the Docket identifies the electrical 

output capacity for MWC units that 

produce electricity as reflected in EPA’s 

NEEDS database. 

However, despite their relatively 

small electricity-generating potential, 

NOX emissions from MWCs located in 

the transport states identified in this 

proposal are substantial. According to 

the EPA’s NEI database, MWCs emitted 

19,222 tons of NOX in 2017 in the ten 

states included in this proposal that 

contain them. Table 8 of the Non-EGU 

Sectors TSD contains a list of MWC 

facilities located within the states 

included in this proposal along with 

their NOX emissions as reported to the 

NEI. 

The EPA has promulgated NOX

emissions limits for large MWCs, 

defined as those that process 250 tons 

of municipal solid waste per day or 

more at 40 CFR part 60, subpart Cb and 

40 CFR part 60, subpart Eb. Subpart Cb 

is applicable to MWCs that commenced 

construction on or before September 20, 

1994, while Subpart Eb is applicable to 

MWCs that commenced construction, 

modification, or reconstruction after 

September 20, 1994. The NOX limits for 

subpart Cb are found within Tables 1 

and 2 of 40 CFR 60.39b and range from 

165 to 250 ppm depending on the 

combustor design type. The NOX limits 

for Subpart Eb are found at 40 CFR 

60.52b(d) and are 180 ppm during a 

unit’s first year of operation and drop to 

150 ppm afterwards, applicable across 

all combustor types. These limits 

correspond to NOX emissions rates of 

0.31 and 0.26 lbs/MMBtu, respectively. 

Section 182(b)(2) and (f) of the CAA 

requires states with ozone 

nonattainment areas classified as 

Moderate or higher to adopt regulations 

with control requirements representing 

reasonably available control technology 

(RACT) for major sources of VOCs and 

NOX. Sections 184(b)(1)(B) and 182(f) of 

the Act require RACT requirements be 

adopted in all areas included within the 

Ozone Transport Region (OTR). Due 

primarily to the NOX RACT 

requirement, many states within the 

Northeast located within the OTR have 

adopted NOX emissions limits for 

MWCs that are more stringent than what 

would otherwise be required by EPA’s 

NSPS or the emissions guideline for 

these units. For example, the 

Montgomery County Resource Recovery 

Facility in Maryland is required to meet 

a NOX RACT limit of 140 ppm (at 7 

percent oxygen) on a 24-hour block 

average. Additionally, MWC facilities 

located in Virginia operated by Covanta, 

Inc., are required to meet a NOX RACT 

limit of 110 ppm (at 7 percent oxygen) 

on a 24-hour basis, and a limit of 90 

ppm (at 7 percent oxygen) on an annual 

average basis.178 The 110 ppm limit 

equates to a limit of 0.19 lbs/MMBtu. 

The Ozone Transport Commission 

(OTC) issued a report entitled 

‘‘Municipal Waste Combustor 

Workgroup Report’’ in June of 2021. The 


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179This report is also available at https://

otcair.org/upload/Documents/Reports/20210624%

20OTC%20SAS%20MWC%20report%20final.pdf. 

180See ‘‘Notice of Proposed rules Taken by Ozone 

Transport Commission At Annual Public Meeting, 

June 15, 2021’’ included in the Docket for this 

proposed rule. 

181This document is available at: https://

www.epa.gov/sites/default/files/2015-07/ 

documents/catalog_of_chp_technologies.pdf. 

182https://www.epa.gov/airmarkets/results-usingepas-power-sector-modeling-platform-v6-summer2021-reference-case. The EPA notes that 

cogeneration units not exempted from EGU Air 

programs are included in the EPA assessment of 

report is included within the docket for 

this proposal.179 The report notes that 

MWCs are a significant source of NOX

emissions in the OTR, releasing 

approximately 22,000 tons of NOX from 

facilities within 9 OTR states in 2018. 

The report summarizes the results of a 

literature review of state-of-the-art NOX

controls that have been successfully 

installed and concludes that significant 

reductions could be achieved using 

several different technologies described 

in the report, primarily via combustion 

modifications made to MWC units 

already equipped with SNCR. The MWC 

workgroup evaluated the emissions 

reduction potential from two different 

control levels, one based on a NOX

concentration in the effluent of 105 to 

110 ppm, and another based on a limit 

of 130 ppm. The workgroup’s findings 

were that a control level of 105 parts per 

million by volume, dry (ppmvd) on a 

30-day average basis and a 110 ppmvd 

on a 24-hour averaging period would 

reduce NOX emissions from MWCs by 

approximately 7,300 tons annually, and 

that a limit of 130 ppmvd on a 30 dayaverage could achieve a 4,000 ton 

reduction. The report notes that 8 MWC 

units exist that are already subject to 

permit limits of 110 ppm, 7 in Virginia, 

and one in Florida. Studies evaluating 

MWCs similar in design to the large 

MWCs in the OTR found NOX

reductions could be achieved at costs 

ranging from $2,900 to $6,600 per ton of 

NOX reduced. Based on the findings of 

this report, the Commissioners of the 

states within the OTR adopted a 

resolution to develop a recommendation 

for emissions reductions from MWCs 

during their June 15, 2021, annual 

public meeting.180

In light of the above, the EPA requests 

comment on whether NOX limits for 

MWCs located in the states covered by 

this proposed rule should be included 

in the final FIP. Specifically, if NOX

controls are included in the final FIP, 

the EPA requests comment on the 

following issues: 

• What NOX emissions limit and 

averaging time should MWCs be 

required to meet, and in particular 

should the EPA adopt emissions rates of 

105 ppmvd on a 30-day averaging basis 

and 110 ppmvd on a 24-hour averaging 

basis? 

• What types of NOX control 

technology could be used to reduce NOX

emissions at MWCs, and in particular 

should the EPA adopt the combustion 

control modifications made to units 

with previously installed SNCR 

identified by the MWC workgroup? 

• Whether there is information that 

would call into question the OTC 

workgroup’s estimated cost of controls 

for reducing NOX emissions from MWCs 

of $2,900 to $6,600 per ton, and, 

assuming that range is accurate, whether 

there is any justification for not 

requiring these controls in light of their 

relative cost-effectiveness and total level 

of reductions available, which compare 

favorably with the proposed EGU and 

non-EGU control strategies? 

• If the final FIP includes emissions 

reduction requirements for MWCs, 

should any mechanism be available by 

which a particular MWC source could 

seek to establish that meeting the 

required emissions limits is not 

feasible? 

• Is there any evidence that retrofit of 

MWC emissions controls would take 

longer to implement than the 2026 

ozone season? 

• Would it be appropriate to rely on 

existing testing, monitoring, 

recordkeeping, and reporting 

requirements for MWCs under the 

applicable NSPS or other requirements? 

c. Cogeneration Units 

Consistent with prior transport rules, 

fossil fuel-fired boilers and combustion 

turbines that produce both electricity 

and useful thermal energy (generally 

referred to as ‘‘cogeneration units’’) and 

that meet the applicability criteria to be 

included in the CSAPR NOX Ozone 

Season Group 3 Trading Program would 

be subject to the emissions reduction 

requirements established in this 

rulemaking for EGUs. However, those 

applicability criteria—which the EPA is 

not proposing to alter in this rulemaking 

(see Section VII.B.3 of this proposed 

rule)—exempt some cogeneration units 

from coverage as EGUs under the 

trading program. The EPA is proposing 

that fossil fuel-fired boilers and 

combustion turbines that produce both 

electricity and useful thermal energy 

and that do not meet the applicability 

criteria to be included in the CSAPR 

NOX Ozone Season Group 3 Trading 

Program as EGUs would not be subject 

to any other emissions reduction 

requirements under this rulemaking. 

Cogeneration systems can offer 

considerable environmental benefit as 

they often require less fuel to produce 

a given energy output. The average 

efficiency of fossil-fuel fired power 

plants in the United States is 33 percent. 

This means that two-thirds of the energy 

used to produce electricity at most 

power plants in the United States is 

wasted in the form of heat discharged to 

the atmosphere. By recovering wasted 

heat, combined heat and power (CHP) 

systems at cogeneration units typically 

achieve total system efficiencies of 60 to 

80% for producing electricity and useful 

thermal energy. Some systems achieve 

efficiencies approaching 90%. This 

increased efficiency allows the same 

level of energy use to be achieved with 

fewer criteria-pollutant and greenhouse 

gas emissions. Additionally, these 

systems increase the reliability of access 

to electrical power for the facilities they 

serve and reduce the need for electricity 

from regional power plants and their 

associated transmission and distribution 

networks. 

According to information contained 

in the EPA’s Combined Heat and Power 

Partnership’s document ‘‘Catalog of CHP 

Technologies’’,181 there are 4,226 CHP 

installations in the U.S. providing 

83,317 MWe of electrical capacity. Over 

99% of the installations are powered by 

5 equipment types, those being 

reciprocating engines (52 percent), 

boilers/steam turbines (17 percent), gas 

turbines (16 percent), microturbines (8 

percent), and fuel cells (4 percent). The 

majority of the electrical capacity is 

provided by gas turbine CHP systems 

(64 percent) and boiler/steam turbine 

CHP systems (32 percent). The various 

CHP technologies described above are 

available in a large range of sizes, from 

as small as 1 kilowatt reciprocating 

engine systems to as large as 300 

megawatt gas turbine powered systems. 

NOX emissions from fuel cell powered 

systems are negligible, and NOX

emissions from rich-burn reciprocating 

engine, gas turbine, and microturbine 

systems are low, ranging from 0.013 to 

0.05 lbs/mmBTU. NOX emissions from 

lean-burn reciprocating engine systems 

and gas-powered steam turbines systems 

range from 0.1 to 0.2 lbs/mmBTU. The 

highest NOX emitting CHP units are 

solid fuel-fired boiler/steam turbine 

systems which emit NOX at rates 

ranging from 0.2 to 1.2 lbs/mmBTU. A 

preliminary assessment from EPA’s IPM 

Summer 2021 Reference Case model 

suggest that cogeneration units 

exempted from current EPA EGU 

transport programs due to such 

classification are projected to account 

for approximately 5% of nationwide 

summer NOX emissions in 2023.182


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20087 

EGU reduction potential in Section VI.B.1 of this 

proposed rule. 

183US EPA. Our Nation’s Air: Status and Trends 

Through 2019. https://gispub.epa.gov/air/ 

trendsreport/2020/#home. 

184National Emissions Inventory Collaborative 

(2019). 2016v1 Emissions Modeling Platform. 

Retrieved from http://views.cira.colostate.edu/wiki/ 

wiki/10202. 

185Control of Air Pollution from Motor Vehicles: 

Tier 3 Motor Vehicle Emissions and Fuel Standards, 

79 FR 23414 (April 28, 2014). 

186Zawacki 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. 

Under the proposed rule (consistent 

with prior CSAPR rulemakings), certain 

cogeneration units would be exempt 

from coverage under the CSAPR NOX

Ozone Season Group 3 Trading Program 

as EGUs. Specifically, the trading 

program regulations include an 

exemption for a unit that qualifies as a 

cogeneration unit throughout the later of 

2005 or the first 12 months during 

which the unit first produces electricity 

and continues to qualify through each 

calendar year ending after the later of 

2005 or that 12-month period and that 

meets the limitation on electricity sales 

to the grid. In order to meet the trading 

program’s definition of ‘‘cogeneration 

unit’’ under the regulations, a unit (i.e., 

a fossil-fuel-fired boiler or combustion 

turbine) must be a topping-cycle or 

bottoming-cycle type that operates as 

part of a ‘‘cogeneration system.’’ A 

cogeneration system is defined as an 

integrated group of equipment at a 

source (including a boiler, or 

combustion turbine, and a generator) 

designed to produce useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes and 

electricity through the sequential use of 

energy. A topping-cycle unit is a unit 

where the sequential use of energy 

results in production of useful power 

first and then, through use of reject heat 

from such production, in production of 

useful thermal energy. A bottomingcycle unit is a unit where the sequential 

use of energy results in production of 

useful thermal energy first, and then, 

through use of reject heat from such 

production, in production of useful 

power. In order to qualify as a 

cogeneration unit, a unit also must meet 

certain efficiency and operating 

standards in 2005 and each year 

thereafter. The electricity sales 

limitation under the exemption is 

applied in the same way whether a unit 

serves only one generator or serves more 

than one generator. In both cases, the 

total amount of electricity produced 

annually by a unit and sold to the grid 

cannot exceed the greater of one-third of 

the unit’s potential electric output 

capacity or 219,000 MWh. This is 

consistent with the approach taken in 

the Acid Rain Program (40 CFR 

72.7(b)(4)), where the cogeneration-unit 

exemption originated. 

The EPA is requesting comment on 

the proposal to exempt cogeneration 

units meeting the above criteria from 

any emissions reduction requirements 

under this proposed rulemaking. The 

EPA also requests comment on the 

alternative of requiring fossil fuel-fired 

boilers in the non-EGU industries 

identified earlier (Section VI.B.2.a of 

this proposed rule) that serve electricity 

generators and that qualify for an 

exemption from inclusion in the CSAPR 

NOX Ozone Season Group 3 Trading 

Program as EGUs to instead meet the 

same emissions standards, if any, that 

would apply under this proposed 

rulemaking to fossil fuel-fired boilers at 

facilities in the same non-EGU 

industries that do not serve electricity 

generators. These proposed emissions 

standards are set forth in Section VII.C.5 

of this proposed rule. Cogeneration 

units at these facilities are in the nonEGU industries identified in EPA’s nonEGU screening assessment for this 

proposal (although potential emissions 

reductions from such cogeneration units 

were not specifically quantified in the 

assessment). Under this alternative 

approach, to the extent these industries 

have otherwise been determined in this 

proposal to significantly contribute to 

nonattainment or interfere with 

maintenance, the EPA would find that 

cogeneration units in these industries 

should not be excluded from EPA’s 

overall NOX mitigation strategy. 

4. Mobile Source NOX Mitigation 

Strategies 

Under a variety of CAA programs, the 

EPA has established federal emissions 

and fuel quality standards that reduce 

emissions from cars, trucks, buses, 

nonroad engines and equipment, 

locomotives, marine vessels, and aircraft 

(i.e., ‘‘mobile sources’’). Because states 

are generally preempted from regulating 

new vehicles and engines with certain 

exceptions (see generally CAA sections 

209, 177), mobile source emissions are 

primarily controlled through EPA’s 

federal programs. The EPA has been 

regulating mobile source emissions 

since it was established as a federal 

agency in 1970, and all mobile source 

sectors are currently subject to NOX

emissions standards. The EPA factors 

these standards and associated 

emissions reductions into its baseline 

air quality assessment in good neighbor 

rulemaking, including in this proposed 

rule. These data are factored into EPA’s 

analysis at Steps 1 and 2 of the 4-step 

framework. As a result of this long 

history, NOX emissions from onroad and 

nonroad mobile sources have 

substantially decreased (73 percent and 

57 percent since 2002, for onroad and 

nonroad, respectively) 183 and are 

predicted to continue to decrease into 

the future as newer vehicles and engines 

that are subject to the most recent, 

stringent standards replace older 

vehicles and engines.184

For example, in 2014, the EPA 

promulgated new, more stringent 

emissions and fuel standards for lightduty passenger cars and trucks.185 The 

fuel standards took effect in 2017, and 

the vehicle standards phase in between 

2017 and 2025. Other EPA actions that 

are continuing to reduce NOX emissions 

include the Heavy-Duty Engine and 

Vehicle Standards and Highway Diesel 

Fuel Sulfur Control Requirements (66 

FR 5002; January 18, 2001); the Clean 

Air Nonroad Diesel Rule (69 FR 38957; 

June 29, 2004); the Locomotive and 

Marine Rule (73 FR 25098; May 6, 

2008); the Marine Spark-Ignition and 

Small Spark-Ignition Engine Rule (73 FR 

59034; October 8, 2008); the New 

Marine Compression-Ignition Engines at 

or Above 30 Liters per Cylinder Rule (75 

FR 22895; April 30, 2010); and the 

Aircraft and Aircraft Engine Emissions 

Standards (77 FR 36342; June 18, 2012). 

The EPA is currently developing a 

new regulatory effort to reduce NOX and 

other pollution from heavy-duty trucks 

(known as the Cleaner Trucks 

Initiative), as described in the January 

21, 2020, Advance Notice of Proposed 

Rulemaking (85 FR 3306). Heavy-duty 

vehicles are the largest contributor to 

mobile source emissions of NOX and 

will be one of the largest mobile source 

contributors to ozone in 2025.186

Reducing heavy-duty vehicle emissions 

nationally would improve air quality 

where the trucks are operating as well 

as downwind. As required by CAA 

section 202(a)(3)(A) of the Act, the EPA 

will be proposing NOX emissions 

standards that ‘‘reflect the greatest 

degree of emissions reduction 

achievable through the application of 

technology which the Administrator 

determines will be available for the 

model year to which such standards 

apply, giving appropriate consideration 

to cost, energy, and safety factors 

associated with the application of such 

technology.’’ Section 202(a)(3)(C) of the 

Act requires that standards apply for no 

less than 3 model years and apply no 

earlier than 4 years after promulgation. 

The EPA’s existing regulatory 

program for mobile sources will 


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187The only coal-fired power plant in California 

is the 63 MW Argus Cogeneration facility in Trona, 

California. 

continue to reduce NOX emissions into 

the future, and the EPA is currently 

taking active steps to ensure that these 

NOX reductions occur. The CAA 

prohibits tampering with emissions 

controls, as well as manufacturing, 

selling, and installing aftermarket 

devices intended to defeat those 

controls. The EPA currently has a 

National Compliance Initiative called 

‘‘Stopping Aftermarket Defeat Devices 

for Vehicles and Engines,’’ which 

focuses on stopping the manufacture, 

sale, and installation of hardware and 

software specifically designed to defeat 

required emissions controls on onroad 

and nonroad vehicles and engines. 

C. Control Stringencies Represented by 

Cost Threshold ($ per Ton) and 

Corresponding Emissions Reductions 

1. EGU Emissions Reduction Potential 

by Cost Threshold 

For EGUs, as discussed in Section 

VI.A of this proposed rule, the multifactor test considers increasing levels of 

uniform control stringency in 

combination with considering total NOX

reduction potential and corresponding 

air quality improvements. The EPA 

evaluated EGU NOX emissions controls 

that are widely available (described 

previously in Section VI.B.1 of this 

proposed rule), that were assessed in 

previous rules to address ozone 

transport, and that have been 

incorporated into state planning 

requirements to address ozone 

nonattainment. 

The EPA evaluated the EGU sources 

within the state of California and found 

there were no covered coal steam 

sources greater than 100 MW that would 

have emissions reduction potential 

according to EPA’s assumed EGU SCR 

retrofit mitigation technologies.187 The 

EGUs in the state are sufficiently wellcontrolled resulting in the lowest fossilfuel emission rate and highest share of 

renewable generation among the 26 

states examined at Step 3. EPA’s Step 3 

analysis, including analysis of the 

emissions reduction factors from EGU 

sources in the state, therefore resulted in 

no additional emission reductions 

required to eliminate significant 

contribution from any EGU sources in 

California. 

The tables below summarize the 

emissions reduction potentials (in ozone 

season tons) from these emissions 

controls across the affected 

jurisdictions. Table VI.C.1–1 focuses on 

near-term emissions controls while 

Table VI.C.1–2 includes emissions 

controls with extended implementation 

timeframes. 

TABLE VI.C.1–1—EGU OZONE-SEASON EMISSIONS AND REDUCTION POTENTIAL (tons)—2023 

State Baseline 2023 

OS NOX

Reduction potential (tons) for varying levels of technology inclusion 

SCR 

optimization 

SCR optimization 

+ combustion control 

upgrades * 

SCR/SNCR optimization 

+ combustion control 

upgrades 

SCR/SNCR optimization 

+ combustion control 

upgrades + generation 

shifting 

Alabama ................................................................ 6,648 32 156 156 387 

Arkansas ............................................................... 8,955 28 28 28 66 

Delaware ............................................................... 423 35 35 39 35 

Illinois .................................................................... 7,662 70 70 247 120 

Indiana ................................................................... 12,351 856 856 865 1,191 

Kentucky ................................................................ 13,900 446 1,047 1,047 2,260 

Louisiana ............................................................... 9,987 579 579 675 579 

Maryland ................................................................ 1,208 0 0 8 13 

Michigan ................................................................ 10,737 4 4 19 4 

Minnesota .............................................................. 4,207 98 98 139 246 

Mississippi ............................................................. 5,097 73 697 697 697 

Missouri ................................................................. 20,094 7,345 7,345 7,569 8,013 

Nevada .................................................................. 2,346 66 66 66 66 

New Jersey ........................................................... 915 105 105 105 116 

New York ............................................................... 3,927 64 64 64 164 

Ohio ....................................................................... 10,295 1,161 1,161 1,161 1,926 

Oklahoma .............................................................. 10,463 199 890 890 890 

Pennsylvania ......................................................... 12,242 2,878 2,878 2,978 3,287 

Tennessee ............................................................. 4,319 110 110 110 85 

Texas ..................................................................... 40,860 921 921 1,154 2,344 

Utah ....................................................................... 15,500 7 7 7 519 

Virginia .................................................................. 3,415 164 242 296 271 

West Virginia ......................................................... 14,686 554 1,099 1,380 1,927 

Wisconsin .............................................................. 5,933 7 7 26 -50 

Wyoming ............................................................... 10,191 82 677 690 1,648 

Total ............................................................... 236,363 15,883 19,143 20,417 26,806 

* The EPA shows reduction potential from state-of-the-art LNB upgrade as near-term reduction emissions controls, but explains in Section VI.B and VI.D of this proposed rule that this reduction potential would not be implemented until 2024 for states not included in the Revised CSAPR Update. 


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188The EPA determined that the 2019 inventory 

was appropriate because it provided a more 

accurate prediction of potential near-term non-EGU 

emissions reductions. 

TABLE VI.C.1–2—EGU OZONE-SEASON EMISSIONS AND REDUCTION POTENTIAL (tons)—2026 

State Baseline 2026 

OS NOX

Reduction potential (tons) for varying levels of technology inclusion 

SCR 

optimization 

SCR 

optimization 

+ combustion 

control 

upgrades 

SCR/SNCR optimization 

+ combustion control 

upgrades 

SCR/SNCR optimization 

+ combustion control 

upgrades 

+ SCR/SNCR 

retrofits 

SCR/SNCR optimization 

+ combustion 

control upgrades 

+ SCR/SNCR 

retrofits + generation 

shifting 

Alabama .................................... 6,701 32 156 156 916 916 

Arkansas ................................... 8,728 28 28 28 4,697 4,805 

Delaware ................................... 473 35 35 39 39 39 

Illinois ........................................ 7,763 70 70 247 1,298 1,648 

Indiana ....................................... 9,737 720 720 729 1,740 1,946 

Kentucky .................................... 13,211 446 885 885 5,450 5,638 

Louisiana ................................... 9,854 579 579 675 6,102 6,102 

Maryland .................................... 1,208 0 0 8 8 19 

Michigan .................................... 9,129 4 4 19 2,959 3,015 

Minnesota .................................. 4,197 98 98 139 1,613 1,661 

Mississippi ................................. 5,077 73 697 697 3,164 3,163 

Missouri ..................................... 18,610 7,345 7,345 7,569 11,237 11,364 

Nevada ...................................... 2,438 66 66 66 1,227 1,227 

New Jersey ............................... 915 105 105 105 105 116 

New York ................................... 3,927 64 64 64 589 689 

Ohio ........................................... 10,295 1,161 1,161 1,161 1,354 1,709 

Oklahoma .................................. 10,283 199 890 890 5,968 6,008 

Pennsylvania ............................. 11,738 2,737 2,737 2,837 4,510 4,919 

Tennessee ................................. 4,064 81 81 81 81 81 

Texas ......................................... 39,186 921 921 1,154 15,817 17,240 

Utah ........................................... 9,679 7 7 7 7,076 7,059 

Virginia ...................................... 3,243 164 242 263 646 676 

West Virginia ............................. 14,686 554 1,099 1,380 3,660 4,089 

Wisconsin .................................. 3,628 7 7 26 54 155 

Wyoming ................................... 10,249 82 677 690 5,669 5,759 

Total ................................... 219,017 15,577 18,675 19,917 85,978 90,041 

2. Non-EGU Emissions Reduction 

Potential—Cost Threshold Up to $7,500/ 

ton 

The EPA used the updated non-EGU 

screening assessment for 2026 to 

estimate emissions reduction potential 

from the Tier 1 and Tier 2 industries 

and non-EGU emissions units. The EPA 

used CoST to identify emissions units, 

emissions reductions, and associated 

compliance costs to evaluate the effects 

of potential non-EGU emissions control 

measures and technologies. CoST is 

designed to be used for illustrative 

control strategy analyses (e.g., NAAQS 

regulatory impact analyses) and not for 

unit-specific, detailed engineering 

analyses. These estimates from CoST 

identify proxies for (1) non-EGU 

emissions units that have emissions 

reduction potential, (2) potential 

controls for and emissions reductions 

from these emissions units, and (3) 

control costs from the potential controls 

on these emissions units. The cost 

estimates do not include monitoring, 

recordkeeping, reporting, or testing 

costs. 

To prepare the non-EGU screening 

assessment for 2026, the EPA applied 

the analytical framework detailed in 

Section VI.B.2 of this proposed rule. 

The assessment includes emissions 

units from the Tier 1 industries and 

impactful high-emitting boilers in Tier 2 

Industries. Using the latest air quality 

modeling for 2026, the EPA identified 

upwind states linked to downwind 

nonattainment or maintenance receptors 

using the 1% of the NAAQS threshold 

criterion, or 0.7 ppb. In 2026 there are 

23 linked states for the 2015 ozone 

NAAQS: Arkansas, California, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, Nevada, New 

Jersey, New York, Ohio, Oklahoma, 

Pennsylvania, Texas, Utah, Virginia, 

West Virginia, Wisconsin, and 

Wyoming. 

The EPA re-ran CoST with known 

controls, the CMDB, and the 2019 

emissions inventory.188 The EPA 

specified CoST to allow replacing an 

existing control if a replacement control 

is estimated to be greater than 10% 

more effective than the existing control. 

The EPA did not replace an existing 

control if the 2019 emissions inventory 

indicated the presence of that control, 

even if the CMDB reflects a greater 

control efficiency for that control. Also, 

the EPA removed six facilities from 

consideration because they are subject 

to an existing consent decree, are shut 

down, or will shut down by 2026. For 

additional detail on the six facilities 

removed, see Appendix B in the NonEGU Screening Assessment 

memorandum. Table VI.C.2–1 

summarizes the estimated reductions, 

total ppb improvements across all 

receptors, and annual total and average 

annual costs (in 2016 dollars) and Table 

VI.C.2–2 below summarizes the 

estimated reductions by state. 


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TABLE VI.C.2–1—ESTIMATED EMISSIONS REDUCTIONS (OZONE SEASON TONS), TOTAL PPB IMPROVEMENTS ACROSS ALL

DOWNWIND RECEPTORS, AND COSTS

Tier 

Ozone season 

emissions reductions 

(East/West) 

Total PPB 

improvement 

across all 

downwind 

receptors 

Annual total cost 

(million 2016$) 

(average annual 

cost/ton) 

Industries 

(# of emissions units >100 tpy in identified industries) 

Tier 1 Industries with Known Controls 

that Cost up to $7,500/ton.

41,153 (37,972/3,181) 4.352 $356.6 ($3,610) Cement and Concrete Product Manufacturing (47) Glass 

and Glass Product Manufacturing (44) Iron and Steel 

Mills & Ferroalloy Manufacturing (39) Pipeline Transportation of Natural Gas (307). 

Tier 2 Industry Boilers with Known 

Controls that Cost up to $7,500/ton.

6,033 (5,965/68) 0.809 54.2 (3,744) Basic Chemical Manufacturing (17) Petroleum and Coal 

Products Manufacturing (10) Pulp Paper, and Paperboard Mills (25). 

TABLE VI.C.2–2—ESTIMATED EMISSIONS REDUCTIONS (OZONE SEASON TONS) BY UPWIND STATE * ** 

State 2019 OS NOX emissions OS NOX reductions 

AR ............................................................................................................................................ 8,265 1,654 

CA ............................................................................................................................................ 14,579 1,666 

IL .............................................................................................................................................. 16,870 2,452 

IN ............................................................................................................................................. 19,604 3,175 

KY ............................................................................................................................................ 11,934 2,291 

LA ............................................................................................................................................. 35,831 6,769 

MD ........................................................................................................................................... 2,365 45 

MI ............................................................................................................................................. 18,996 2,731 

MN ........................................................................................................................................... 17,591 673 

MO ........................................................................................................................................... 9,109 3,103 

MS ............................................................................................................................................ 12,284 1,761 

NJ ............................................................................................................................................. 2,025 0 

NV ............................................................................................................................................ 2,418 0 

NY ............................................................................................................................................ 6,003 500 

OH ............................................................................................................................................ 19,729 2,790 

OK ............................................................................................................................................ 22,146 3,575 

PA ............................................................................................................................................ 15,861 3,284 

TX ............................................................................................................................................ 47,135 4,440 

UT ............................................................................................................................................ 6,276 757 

VA ............................................................................................................................................ 7,041 1,563 

WI ............................................................................................................................................. 6,571 2,150 

WV ........................................................................................................................................... 9,825 982 

WY ........................................................................................................................................... 10,335 826 

Total .................................................................................................................................. 322,793 47,187 

* In the non-EGU screening assessment, EPA estimated emissions reduction potential from the non-EGU industries and emissions units. The 

estimated emissions reductions by state in the table above are from the non-EGU screening assessment; for additional results from the non-EGU 

screening assessment, including estimated reductions by state and by industry, please see the Non-EGU Screening Assessment memorandum 

available in the docket. 

** In the assessment, EPA used CoST to identify emissions units, emissions reductions, and associated compliance costs to evaluate the effects of potential non-EGU emissions control measures and technologies. CoST is designed to be used for illustrative control strategy analyses 

(e.g., NAAQS regulatory impact analyses) and not for unit-specific, detailed engineering analyses. These estimates from CoST identify proxies 

for (1) non-EGU emissions units that have emissions reduction potential, (2) potential controls for and emissions reductions from these emissions 

units, and (3) control costs from the potential controls on these emissions units. The cost estimates do not include monitoring, recordkeeping, reporting, or testing costs. 

In this section, EPA provides a 

summary of the control technologies 

applied and their average costs across 

all of the non-EGU emissions units 

included in the screening assessment. 

This summary reflects one approach to 

organizing this information, which the 

Agency finds reasonable based on the 

information available for this proposal. 

As discussed in Section VI.B.2 of this 

proposed rule, the number of different 

industries and emissions unit categories 

and types present a challenge to 

defining a single method to identify 

appropriate control technologies, 

measures or strategies, and related costs 

across non-EGU emissions units. 

Because of the number of industries and 

emissions unit types, the available 

information does not easily allow 

grouping estimated emissions 

reductions by cost per ton threshold for 

a few control technologies, measures, or 

strategies. Nonetheless, Table VI.C.2–3 

below provides a summary of estimated 

reductions and average cost per ton 

values by control technology across all 

non-EGU emissions units included in 

the non-EGU screening assessment. The 

summary reflects fourteen control 

technologies applied by CoST across all 

emissions units in the non-EGU 

screening assessment. The average cost 

per ton values range from $585 to 

$6,300 per ton, all of which are below 

the marginal cost per ton threshold of 

$7,500 per ton. Note that the average 

cost per ton values are in 2016 dollars 

and reflect simple averages and not a 

percentile or other representative cost 

values from a distribution of cost 

estimates. 

The Non-EGU Screening Assessment 

memorandum includes two other 

summaries of estimated reductions and 

average cost per ton values by 

technology across non-EGU emissions 

units. First, the memorandum includes 

a summary by control technology as 

applied across non-EGU emissions units 

grouped by the Tier 1 industries and 


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impactful boilers in Tier 2 industries, 

which given this further disaggregation 

reflects 18 control technologies across 

the tiers applied by CoST. Second, the 

memorandum includes a summary by 

control technology across non-EGU 

emissions units grouped by the seven 

individual Tier 1 and 2 industries, 

which given this disaggregation reflects 

26 control technologies across the 

industries applied by CoST. 

TABLE VI.C.2–3—ESTIMATED EMISSIONS REDUCTIONS (OZONE SEASON TONS), ANNUAL TOTAL COST, AND AVERAGE

COST PER TON BY CONTROL TECHNOLOGY ACROSS ALL NON-EGU EMISSIONS UNITS

Control technology 

Ozone season 

emissions 

reductions 

Average cost 

per ton 

Adjust Air to Fuel Ratio and Ignition Retard ........................................................................... 212 $2,393 

Layered Combustion ................................................................................................................ 12,706 5,457 

Low NOX Burner ...................................................................................................................... 231 3,773 

Low NOX Burner and Flue Gas Recirculation ......................................................................... 200 4,288 

Natural Gas Reburn ................................................................................................................. 284 2,703 

Non-Selective Catalytic Reduction .......................................................................................... 147 585 

Non-Selective Catalytic Reduction or Layered Combustion ................................................... 6,359 4,743 

Oxygen Enriched Air Staging .................................................................................................. 52 764 

SCR + DLN Combustion ......................................................................................................... 136 6,301 

Selective Catalytic Reduction .................................................................................................. 12,239 2,543 

Selective Catalytic Reduction and Steam Injection ................................................................. 929 3,787 

Selective Non-Catalytic Reduction .......................................................................................... 8,076 1,485 

Ultra-Low NOX Burner ............................................................................................................. 1,670 2,890 

Ultra-Low NOX Burner and Selective Catalytic Reduction ...................................................... 3,946 4,114 

Refer to the Non-EGU Screening 

Assessment memorandum for additional 

2026 screening assessment results— 

including by industry and by state, 

estimated emissions reductions and 

costs, as well as by industry, emissions 

source groups, control technologies, 

number of emissions units, estimated 

ozone season reductions, and annual 

total cost. 

D. Assessing Cost, EGU and Non-EGU 

NOX Reductions, and Air Quality 

To determine the emissions that are 

significantly contributing to 

nonattainment or interfering with 

maintenance, the EPA applied the 

multi-factor test to EGUs and non-EGUs 

separately, considering for each the 

relationship of cost, available emissions 

reductions, and downwind air quality 

impacts. Specifically, for each sector, 

the EPA proposes a determination 

regarding the appropriate level of 

uniform NOX control stringency that 

would collectively eliminate significant 

contribution to downwind 

nonattainment and maintenance 

receptors. The EPA also evaluated 

whether the proposed rule resulted in 

possible over-control scenarios by 

evaluating if an upwind state is linked 

solely to downwind air quality 

problems that could have been resolved 

at a lower cost threshold, or if an 

upwind state could have reduced its 

emissions below the 1 percent air 

quality contribution threshold at a lower 

cost threshold. 

1. EGU Assessment 

For EGUs, the EPA examined the 

emissions reduction potential associated 

with each EGU emissions control 

technology (presented in Section VI.C.1 

of this proposed rule) and its impact on 

the air quality at downwind receptors. 

Specifically, EPA identified and 

assessed the projected average air 

quality improvements relative to the 

base case and whether these 

improvements are sufficient to shift the 

status of receptors from projected 

nonattainment to maintenance or from 

maintenance to attainment. Combining 

these air quality factors, costs, and 

emissions reductions, the EPA 

identified a control stringency for EGUs 

that results in substantial air quality 

improvement from emissions controls 

that are available in the timeframe for 

which air quality problems at 

downwind receptors persist. For all 

affected jurisdictions, this control 

stringency reflects, at a minimum, the 

optimization of existing postcombustion controls and installation of 

state-of-the-art NOX combustion 

controls, which are widely available at 

a representative marginal cost of $1,800 

per ton. EPA’s evaluation also shows 

that the effective emissions rate 

performance across affected EGUs 

consistent with realization of these 

mitigation measures does not overcontrol upwind states’ emissions 

relative to either the downwind air 

quality problems to which they are 

linked at Step 1 or the 1 percent 

contribution threshold that triggers 

further evaluation at Step 3 of the 4-step 

framework for the 2015 ozone NAAQS. 

Similarly, the EPA also identified 

installation of new SCR postcombustion controls at coal steam 

sources greater than or equal to 100 MW 

and for a more limited portion of the 

oil/gas steam fleet that had higher levels 

of emissions as components of the 

required control stringency. These SCR 

retrofits are widely available by the 

2026 ozone season at $11,000 and 

$7,700 per ton respectively. For all but 

3 of the affected states (Alabama, 

Delaware, and Tennessee—which are no 

longer linked in 2026 at Steps 1 and 2 

in EPA’s base case air quality modeling), 

EPA’s evaluation also shows that the 

effective emissions rate performance 

across EGUs consistent with realization 

of these mitigation measures does not 

over-control upwind states’ emissions in 

2026 relative to either the downwind air 

quality problems to which they are 

linked at Step 1 or the 1 percent 

contribution threshold that triggers 

further evaluation at Step 3 of the 4-step 

framework for the 2015 ozone NAAQS 

(see the Ozone Transport Policy 

Analysis Proposed Rule TSD for 

details). 

To assess downwind air quality 

impacts for the nonattainment and 

maintenance receptors identified in 

Section V.D of this proposed rule, the 

EPA evaluated the air quality change at 

that receptor expected from the 

progressively more stringent upwind 

EGU control stringencies that were 

available for that time period in upwind 

states linked to that receptor. This 

assessment provides the downwind 

ozone improvements for consideration 

and provides air quality data that is 


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189For EGUs, this analysis for the Connecticut 

receptors shows no EGU reduction potential from 

the emissions reduction measures identified given 

that state’s already low-emitting fleet; however, 

EGU reductions were identified in Colorado and 

these reductions were included in the over-control 

analysis. 

190As in prior rules, for the purpose of defining 

significant contribution at Step 3, the EPA 

evaluated air quality changes resulting from the 

application of the emissions reductions in only 

those states that are linked to each receptor as well 

as the state containing the receptor. By applying 

reductions to the state containing the receptor, the 

EPA ensures that it is accounting for the downwind 

state’s fair share. This method holds each upwind 

state responsible for its fair share of the downwind 

problems to which it is linked. Reductions made by 

other states in order to address air quality problems 

at other receptors do not increase or decrease this 

share. The air quality impacts on design values that 

reflect the emissions reductions in all linked states 

and the health and climate benefits from this 

proposal are discussed in Section IX of this 

proposed rule. 

used to evaluate potential over-control 

situations. 

To assess the air quality impacts of 

the various control stringencies at 

downwind receptors for the purposes of 

Step 3, the EPA evaluated changes 

resulting from the emissions reductions 

associated with the identified emissions 

controls in each of the upwind states, as 

well as assumed corresponding 

reductions of similar stringency in the 

downwind state containing the receptor 

to which they are linked. By applying 

these emissions reductions to the state 

containing the receptor, the EPA 

assumes that the downwind state will 

implement (if it has not already) an 

emissions control stringency for its 

sources that is comparable to the 

upwind control stringency identified 

here. Consequently, The EPA is 

accounting for the downwind state’s 

share of a nonattainment or 

maintenance problem as a part of the 

over-control evaluation.189

For this assessment, the EPA used an 

ozone air quality assessment tool (ozone 

AQAT) to estimate downwind changes 

in ozone concentrations related to 

upwind changes in emissions levels. 

The EPA focused its assessment on the 

years 2023 and 2026 as they pertain to 

the last years for which ozone season 

emissions data can be used for purposes 

of determining attainment for the 

Moderate (2024) and Serious (2027) 

attainment dates. For each EGU 

emissions control technology, the EPA 

first evaluated the magnitude of the 

change in ozone concentrations at the 

nonattainment and maintenance 

receptors for each relevant year (i.e., 

2023 and 2026). Next, the EPA 

evaluated whether the estimated change 

in concentration would resolve the 

receptor’s nonattainment or 

maintenance concern by lowering the 

average or maximum design values, 

respectively, below 71 ppb. For a 

complete set of estimates, see the Ozone 

Transport Policy Analysis Proposed 

Rule TSD or the ozone AQAT excel file. 

For 2023, the EPA evaluated potential 

air quality improvements at the 

downwind receptors outside of 

California associated with available 

EGU emissions control technologies in 

that timeframe. The EPA determined for 

the purposes of Step 3 that the average 

air quality improvement at the receptors 

relative to the engineering analytics base 

case was 0.11 ppb for emissions 

reductions commensurate with 

optimization of existing SCRs/SNCRs 

and combustion control upgrades. The 

EPA determined for the purposes of 

Step 3 that one receptor in Clark 

County, Nevada switches from 

maintenance to attainment with these 

mitigation strategies in place. Table 

VI.D.1–1 summarizes the results of 

EPA’s Step 3 evaluation of air quality 

improvements at these receptors using 

AQAT. 

For 2026, the EPA determined that the 

average air quality improvement at these 

receptors relative to the engineering 

analytics base case was 0.43 ppb for 

emissions reductions commensurate 

with optimization of existing SCRs/ 

SNCRs, combustion control upgrades, 

and new post-combustion control (SCR 

and SNCR) retrofits at eligible units are 

assumed to be implemented. The EPA 

determined for the purposes of Step 3 

that in 2026, all but one of the receptors 

are expected to remain nonattainment or 

maintenance across these control 

stringencies, with one receptor in 

Douglas County, Colorado switching 

from maintenance to attainment with 

these mitigation strategies in place.190

Table VI.D.1–2 summarizes the results 

of EPA’s Step 3 evaluation of air quality 

improvements at the receptors included 

in the AQAT analysis. For more 

information about how this assessment 

was performed and the results of the 

analysis for each receptor, refer to the 

Ozone Transport Policy Analysis 

Proposed Rule TSD and to the Ozone 

AQAT included in the docket for this 

rule. 

TABLE VI.D.1–1—AIR QUALITY AT THE 29 RECEPTORS IN 2023 FROM EGU EMISSIONS CONTROL TECHNOLOGIES a b

Monitor ID No. State County 

Average DV 

(ppb) 

Max DV 

(ppb) 

Baseline 

(engineering 

analysis) 

SCR/SNCR 

optimization + 

LNB upgrade 

Baseline 

(engineering 

analysis) 

SCR/SNCR 

optimization + 

LNB upgrade 

040278011 ...................... Arizona ............................ Yuma ............................... 70.53 70.53 72.25 72.24 

080350004 ...................... Colorado .......................... Douglas ........................... 72.35 72.28 72.96 72.89 

080590006 ...................... Colorado .......................... Jefferson ......................... 73.23 73.19 73.84 73.80 

080590011 ...................... Colorado .......................... Jefferson ......................... 74.41 74.38 75.13 75.09 

090010017 ...................... Connecticut ..................... Fairfield ........................... 73.11 73.14 73.82 73.85 

090013007 ...................... Connecticut ..................... Fairfield ........................... 74.45 74.44 75.37 75.36 

090019003 ...................... Connecticut ..................... Fairfield ........................... 76.30 76.29 76.51 76.50 

090099002 ...................... Connecticut ..................... New Haven ..................... 72.11 72.07 74.16 74.12 

170310001 ...................... Illinois .............................. Cook ................................ 70.02 70.02 73.90 73.89 

170310032 ...................... Illinois .............................. Cook ................................ 70.14 70.15 72.78 72.79 

170310076 ...................... Illinois .............................. Cook ................................ 69.64 69.65 72.49 72.49 

170314201 ...................... Illinois .............................. Cook ................................ 70.19 70.18 73.75 73.74 

170317002 ...................... Illinois .............................. Cook ................................ 70.42 70.33 73.37 73.29 

320030075 ...................... Nevada ............................ Clark ................................ 70.09 70.06 71.01 70.98 

420170012 ...................... Pennsylvania ................... Bucks .............................. 71.09 71.03 72.63 72.57 

480391004 ...................... Texas .............................. Brazoria ........................... 71.71 71.29 73.89 73.45 

481210034 ...................... Texas .............................. Denton ............................. 71.20 71.03 73.06 72.89 

482010024 ...................... Texas .............................. Harris ............................... 76.92 76.55 78.48 78.10 

482010055 ...................... Texas .............................. Harris ............................... 72.50 72.14 73.54 73.17 

482011034 ...................... Texas .............................. Harris ............................... 72.07 71.67 73.32 72.91 

482011035 ...................... Texas .............................. Harris ............................... 69.69 69.31 73.32 72.92 

490110004 ...................... Utah ................................. Davis ............................... 73.65 73.59 75.91 75.85


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191 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

192 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

193 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

TABLE VI.D.1–1—AIR QUALITY AT THE 29 RECEPTORS IN 2023 FROM EGU EMISSIONS CONTROL TECHNOLOGIES a b— 

Continued 

Monitor ID No. State County 

Average DV 

(ppb) 

Max DV 

(ppb) 

Baseline 

(engineering 

analysis) 

SCR/SNCR 

optimization + 

LNB upgrade 

Baseline 

(engineering 

analysis) 

SCR/SNCR 

optimization + 

LNB upgrade 

490353006 ...................... Utah ................................. Salt Lake ......................... 74.35 74.29 75.99 75.93 

490353013 ...................... Utah ................................. Salt Lake ......................... 75.27 75.21 75.78 75.72 

490570002 ...................... Utah ................................. Weber .............................. 71.35 71.29 73.29 73.23 

490571003 ...................... Utah ................................. Weber .............................. 71.24 71.19 72.16 72.11 

550590019 ...................... Wisconsin ........................ Kenosha .......................... 73.17 73.07 74.09 73.99 

550590025 ...................... Wisconsin ........................ Kenosha .......................... 69.62 69.46 72.69 72.52 

551010020 ...................... Wisconsin ........................ Racine ............................. 71.70 71.61 73.64 73.55 

Average AQ Change Relative to Base (ppb) ....................................................................................................................................................... 0.11 

Total PPB Change Across All Receptors Relative to Base c ............................................................................................................................... 3.08 

Table Notes: 

a These results reflect the inclusion of all identified LNB upgrade potential. Some of which will be implemented in 2023 state emissions budgets, and some be implemented in 2024 state emissions budgets (for those states not included in the Revised CSAPR Update). b The EPA notes that the design values reflected in tables VI.D.1–1 and 2 correspond to the engineering analysis EGU emissions inventory that was used in AQAT 

to determine state-level baseline emissions and reductions at Step 3. These tools are discussed in greater detail in the Ozone Transport Policy Analysis Proposed 

Rule TSD. c The cumulative ppb change only shows the aggregate change across all problematic receptors (some of which are located within close proximity to one another) 

in this part of the Step 3 analysis. Section IX of this proposed rule provides a more complete picture of the air quality impacts of the proposed rule. 

TABLE VI.D.1–2—AIR QUALITY AT RECEPTORS IN 2026 FROM EGU EMISSIONS CONTROL TECHNOLOGIES

Monitor ID No. State County 

Average DV 

(ppb) 

Max DV 

(ppb) 

Baseline 

(engineering 

analysis) 

SCR/SNCR 

optimization 

+ LNB upgrade 

+ SCR/SNCR 

retrofit 

Baseline 

(engineering 

analysis) 

SCR/SNCR optimization 

+ LNB upgrade + 

SCR/SNCR retrofit 

40278011 ........................ Arizona ............................ Yuma ............................... 70.11 70.09 71.81 71.79 

80350004 ........................ Colorado .......................... Douglas ........................... 70.94 70.23 71.55 70.83 

80590006 ........................ Colorado .......................... Jefferson ......................... 72.09 71.42 72.69 72.02 

80590011 ........................ Colorado .......................... Jefferson ......................... 72.97 72.32 73.68 73.02 

90010017 ........................ Connecticut ..................... Fairfield ........................... 71.60 71.52 72.30 72.22 

90013007 ........................ Connecticut ..................... Fairfield ........................... 73.09 72.84 73.99 73.74 

90019003 ........................ Connecticut ..................... Fairfield ........................... 74.83 74.63 75.03 74.83 

90099002 ........................ Connecticut ..................... New Haven ..................... 70.77 70.51 72.78 72.51 

170310001 ...................... Illinois .............................. Cook ................................ 69.05 68.96 72.87 72.77 

170310032 ...................... Illinois .............................. Cook ................................ 69.37 69.32 71.98 71.93 

170310076 ...................... Illinois .............................. Cook ................................ 68.75 68.71 71.56 71.52 

170314201 ...................... Illinois .............................. Cook ................................ 69.10 69.02 72.61 72.53 

170317002 ...................... Illinois .............................. Cook ................................ 69.36 69.18 72.27 72.09 

480391004 ...................... Texas .............................. Brazoria ........................... 70.93 69.35 73.09 71.46 

482010024 ...................... Texas .............................. Harris ............................... 76.28 74.77 77.82 76.28 

490110004 ...................... Utah ................................. Davis ............................... 72.20 71.61 74.42 73.81

490353006 ...................... Utah ................................. Salt Lake ......................... 73.00 72.40 74.61 74.00 

490353013 ...................... Utah ................................. Salt Lake ......................... 74.10 73.45 74.60 73.95 

490570002 ...................... Utah ................................. Weber .............................. 70.30 69.74 72.22 71.64 

550590019 ...................... Wisconsin ........................ Kenosha .......................... 72.01 71.80 72.91 72.70 

550590025 ...................... Wisconsin ........................ Kenosha .......................... 68.46 68.19 71.48 71.19 

551010020 ...................... Wisconsin ........................ Racine ............................. 70.52 70.33 72.42 72.24 

Average AQ Change Relative to Base (ppb) ....................................................................................................................................................... 0.43 

Total PPB Change Across All Receptors Relative to Base (ppb) ........................................................................................................................ 9.42 

Figures 1 and 2 to Section VI.D.1, 

included in Appendix G of the Ozone 

Transport Policy Analysis Proposed 

Rule TSD available in the docket for this 

rulemaking, illustrate the air quality 

improvement relative to the estimated 

representative cost associated with the 

previously identified emissions control 

technologies. The graphs show 

improving air quality at the downwind 

receptors as emissions reductions 

commensurate with the identified 

control technologies are assumed to be 

implemented. Figure 1 to Section 

VI.D.1 191 reflects emissions reductions 

commensurate with optimization of 

existing SNCRs and SCRs. Figure 2 to 

Section VI.D.1 192 reflects emissions 

reductions commensurate with 

installation of new post combustion 

controls (mainly SCRs) layered on top of 

the emissions reduction potential from 

the technologies represented in Figure 1 

to Section VI.D.1.193 The graphic, and 

underlying AQAT receptor-by-receptor 

analysis demonstrates that air quality 

continues to improve at downwind 

receptors as EPA examines increasingly 

stringent EGU NOX control 


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194 63 FR 57448. 

195 71 FR 25345. 

196EPA–HQ–OAR–2020–0272. Comment letter 

from Attorneys General of NY, NJ, CT, DE, MA. 

197COMAR 26.11.38 (control of NOX Emissions 

from Coal-Fired Electric Generating Units). 

198https://www.epa.gov/system/files/documents/ 

2021-09/table-3-30-state-power-sector-regulationsincluded-in-epa-platform-v6-summer-2021-refe.pdf. 

199See table 3–35 BART regulations in EPA IPM 

documentation available at https://www.epa.gov/ 

airmarkets/documentation-epas-power-sectormodeling-platform-v6-summer-2021-reference-case. 

200 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

201 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

technologies. While all major 

technology breakpoints identified in 

Sections VI.B and VI.C of this proposed 

rule show continued air quality 

improvements at problematic receptors 

and at cost and technology choice levels 

that are commensurate with mitigation 

strategies that are proven to be widely 

available and implemented, EPA’s 

quantification and application of those 

breakpoints reflect certain exclusions to: 

(1) Preserve this consistency with 

widely observed mitigation measures in 

states, and (2) remove any retrofit 

assumptions at marginal units that 

would have much higher dollar per ton 

representative cost and little or no air 

quality benefit. For instance, the EPA 

does not define the SCR retrofit 

breakpoint ($11,000 per ton) to include 

retrofit application at steam units less 

than 100 MW or at oil/gas steam units 

emitting at less than 150 tons per ozone 

season. The emissions reductions from 

these potential categories of measures 

are small and do not constitute 

additional ‘‘breakpoints’’ in EPA’s 

estimation. They would entail much 

higher dollar per ton costs, going 

beyond what is widely observed in the 

fleet. This careful calibration of 

technology breakpoints through 

exclusion of measures that are clearly 

not cost-effective in terms of air quality 

benefit allows for the identification of 

an EGU strategy that is an appropriate 

reflection of those readily available and 

widely implemented emissions 

reduction strategies that will have 

meaningful downwind air quality 

impact. 

Moreover, these technologies (and 

representative cost) are demonstrated 

ozone pollution mitigation strategies 

that are widely practiced across the EGU 

fleet and are of comparable stringency to 

emissions reduction measures that 

many downwind states have already 

instituted. The coal SCR retrofit 

measures driving the majority of the 

emissions reductions in this action not 

only reflect industry best practice, but 

they also reflect prevailing practice 

among EGUs. More than 60% of the 

existing coal capacity already has this 

technology in place. For nearly 25 years, 

all new coal-fired EGUs that 

commenced construction have had SCR 

(or equivalent emissions rates). The 

1997 proposed amendments to subpart 

Da revised the NOX standard based on 

the use of SCR. The NOX SIP Call 

(promulgated in 1998) established 

emissions reduction requirements 

premised on extensive SCR installation 

(142 units) and incentivized well over 

40 GWs of SCR retrofit in the ensuing 

years.194 Similarly, the Clean Air 

Interstate Rule established emissions 

reductions requirements in 2006 that 

assumed another 58 units (15 GW) 

would be installed in the ensuing years 

among just 10 states, and an even 

greater volume of capacity chose SCR 

retrofit measures in the wake of 

finalizing that action.195

Basing emission reduction 

requirements for EGUs on SCR retrofits 

is also consistent with regulatory 

approaches adopted by states, which— 

particularly in downwind areas more 

impacted by ozone transport 

contribution from upwind state 

emissions—have already adopted SCRbased standards as part of stringent NOX

control programs. Regulatory programs 

that impose stringent Reasonably 

Available Control Technology (RACT) 

requirements on all major power plants 

and Lowest Achievable Emission Rate 

(LAER) standards on all new major 

sources of NOX have resulted in 

remaining coal sources in states along 

the Northeast Corridor such as 

Connecticut, Delaware, New Jersey, 

New York, and Massachusetts all being 

retrofitted with SCR.196 The Maryland 

Code of Regulations requires coal fired 

sources to operate existing SCR controls 

or install SCR controls by specified 

dates.197 Programs like North Carolina’s 

Clean Smokestacks Act and Colorado’s 

Clean Air, Clean Jobs Act have also 

required or prompted SCR retrofits on 

units.198 Unit-level Best Available 

Retrofit Technology (BART) 

requirements for the first Regional Haze 

planning period also determined SCR 

retrofits (and corresponding emissions 

rates) were cost-effective controls for a 

variety of sources in the U.S.199

As shown in Figure 1 to Section 

VI.D.1,200 the majority of EGU emissions 

reduction potential and associated air 

quality improvements estimated for 

2023 occurs from optimization of 

existing SCRs, with some additional 

reductions from installation of state-ofthe-art combustion controls at the same 

representative cost threshold. At the 

slightly higher representative cost 

threshold of $1,800 per ton, there is 

some additional air quality 

improvement from optimization of 

existing SNCRs. These measures taken 

together represent the control stringency 

at which near-term incremental EGU 

NOX reduction potential and 

corresponding downwind ozone air 

quality improvements are maximized. 

This evaluation shows that EGU NOX

reductions for each of the near-term 

emissions control technologies are 

available at reasonable cost and that 

these reductions provide meaningful 

improvements in downwind ozone 

concentrations at the identified 

nonattainment and maintenance 

receptors. Figure 1 to Section VI.D.1 201

highlights (1) the continuous connection 

between identified emission reduction 

potential and downwind air quality 

improvement across the range of nearterm mitigation measures assessed, and 

(2) the cost-effective availability of these 

reductions and corresponding air 

quality improvements. 

Additional considerations that are 

unique to EGUs provide additional 

support for EPA’s proposal to include 

SCR and SNCR optimization as part of 

the identified near-term control 

stringency, including: 

• These controls are already installed 

and available for operation on these 

units; 

• they are on average already partially 

operating, but not necessarily 

optimized; 

• the reductions are available in the 

near-term (during ozone seasons when 

the problematic receptors are projected 

to persist), including by the 2023 ozone 

season aligned with the Moderate area 

attainment date; and 

• these sources are already covered 

under the existing CSAPR NOX Ozone 

Season Group 2 or Group 3 Trading 

Programs or the Acid Rain Program and 

thus have the monitoring, reporting, 

recordkeeping, and all other necessary 

elements of compliance with the trading 

program already in place. 

The majority of emissions reduction 

potential and associated air quality 

improvements estimated for 2026 occur 

from retrofitting uncontrolled steam 

sources with post-combustion controls. 

At the representative cost threshold of 

$11,000 per ton, there are significant 

additional air quality improvements 

from emissions reductions 

commensurate with installation of new 

SCRs and SNCRs. These measures taken 

together with the near-term emissions 

reduction measures described 


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202 Included in Appendix G of the Ozone 

Transport Policy Analysis Proposed Rule TSD, 

which is available in the docket for this rulemaking. 

203This is not to discount the potential 

effectiveness of these or other NOX mitigation 

strategies outside the context of this rulemaking to 

address regional ozone transport on a nationwide 

basis. States and local jurisdictions may find such 

measures particularly impactful or necessary in the 

context of local attainment planning or other 

unique circumstances. Further, while the EPA 

proposes this rule as a complete remedy to the 

problem of interstate transport for the 2015 ozone 

NAAQS, the EPA has in the past recognized that 

circumstances may arise after the promulgation of 

remedies under CAA section 110(a)(2)(D)(i)(I) in 

which the exercise of further remedial authority 

against specific stationary sources or groups of 

sources under CAA section 126 may be warranted. 

See Response to Clean Air Act Section 126(b) 

Petition From Delaware and Maryland, 83 FR 

50444, 50453–54 (Oct. 5, 2018). 

previously represent the level of control 

stringency in 2026 at which incremental 

EGU NOX reduction potential and 

corresponding downwind ozone air 

quality improvements are maximized. 

This evaluation shows that EGU NOX

reductions for each of the emissions 

control technologies are available at 

reasonable cost and that these 

reductions can provide improvements 

in downwind ozone concentrations at 

the identified nonattainment and 

maintenance receptors. 

The EPA finds that the control 

stringency that reflects optimization of 

existing SCRs and SNCRs, installation of 

state-of-the-art combustion controls, and 

the retrofitting of new post combustion 

controls at the coal and oil/gas steam 

capacity described previously results in 

nearly 90,000 tons of NOX reduction 

(approximately 43 percent of the 2026 

baseline level) for the 22 linked states in 

2026 subject to a FIP for EGUs, which 

will deliver notable air quality 

improvements across all transportimpacted receptors and assist in fully 

resolving one downwind air quality 

problem for the 2015 ozone NAAQS. 

Figure 2 to Section VI.D.1 202

demonstrates the continuous connection 

between identified emissions reduction 

potential and downwind air quality 

improvement across the range of 

mitigation measures assessed in 2026. 

At no point do the additional emission 

mitigation measures examined here fail 

to produce corresponding downwind air 

quality improvements. 

The EPA is proposing that emissions 

reductions commensurate with the full 

operation of all existing postcombustion controls (both SCRs and 

SNCRs) and state-of-the-art combustion 

control upgrades constitute the 

Agency’s selected control stringency for 

EGUs for those states linked to 

downwind nonattainment or 

maintenance in 2023. For those states 

also linked in 2026, the EPA is 

determining that the appropriate EGU 

control stringency also includes 

emissions reductions commensurate 

with the retrofit of SCR at coal steam 

units of 100 MW or greater capacity 

(excepting circulating fluidized bed 

units), new SNCR on coal steam units of 

less than 100 MW capacity and 

circulating fluidized bed units, and SCR 

on oil/gas steam units greater than 100 

MW that have historically emitted at 

least 150 tons of NOX per ozone season. 

As noted previously in Section VI.B of 

this proposed rule and in the EGU NOX

Mitigation Strategies Proposed Rule 

TSD, the EPA considered other methods 

of identifying mitigation measures (e.g., 

SCRs on smaller units, combustion 

control upgrades on combustion 

turbines, SCRs on combustion turbines). 

The emission reductions from these 

potential categories of measures do not 

constitute additional ‘‘technology 

breakpoints’’ in EPA’s estimation, but 

rather reflect a different tier of 

assessment where further mitigation 

measures are based on inclusion of 

smaller and/or different generator type 

of unit (rather than pollution control 

technology). Emissions reductions from 

these measures are relatively small and 

would entail much higher dollar per ton 

costs, going beyond what is widely 

observed in the fleet. Although these 

additional measures are not included in 

EPA’s technology breakpoint analysis 

discussed above, the EPA did examine 

the cost, potential reductions, and air 

quality impact of these additional 

measures in a supplemental analysis to 

affirm that they do not merit inclusion 

in the proposed stringency for this 

action. Similar to prior rules, there is a 

notable ‘‘knee-in-the-curve’’ breakpoint 

if these additional measures are 

included in EPA’s analysis. In other 

words, there are very little additional 

emissions reductions and air quality 

improvement at problematic receptors, 

and the cost associated with these 

measures increases substantially on a 

dollar per ton basis. The graphic below 

illustrates the significant loss in costeffectiveness of reductions if these 

measures had been included in EPA’s 

proposed stringency.203

This proposed determination 

regarding the appropriate level of 

control stringency for EGUs to eliminate 

significant contribution from upwind 

states finds that the amounts of NOX

emissions reduction achieved through 

these strategies at EGUs are necessary 

and cost-justified under the Step 3 

multifactor analysis for as long as the 

strategies remain available to the 

sources. In other words, the EPA finds 

at Step 3 that so long as the identified 

NOX emissions reduction controls are 

available and can be implemented (such 

as optimization of SCRs), they must be 

implemented, even as total NOX

emissions reductions on a mass basis 

decline. EPA’s Step 3 finding is not 

limited to a determination of the massbased reduction in emissions that the 

EPA determines is achievable for the 

covered EGU fleet under current 

operating conditions. Rather, the EPA 

finds at Step 3 that EGUs must continue 

to achieve NOX emissions performance 

in the ozone season commensurate with 

the level of emissions control stringency 

the EPA determines appropriate under 

the multifactor test as set forth in this 

section. The stringency of the emissions 

budgets would simply reflect the 

stringency of the emissions control 

strategies and would do so more 

consistently over time than EPA’s 

previous approach of computing 

emissions budgets for all future control 

periods at the time of the rulemaking. 

This retention of a constant degree of 

stringency over time in emissions 

budgets under a flexible trading 

program would not constitute overcontrol any more than the permanent 

imposition of emissions rate standards 

on individual sources at the time of the 

rulemaking would constitute overcontrol. 

EPA acknowledges that this is an 

adjustment in its historical approach to 

eliminating significant contribution, 

although it is consistent with the 

evolution of the Agency’s thinking as set 

forth in the Revised CSAPR Update. In 

CSAPR and the CSAPR Update, EPA 

established static budgets at Step 4 

based on the selected level of control 

stringency at Step 3. EPA’s experience 

with this approach has been that while 

the initial mass-based budgets are 

achieved and compliance targets are 

even exceeded, this leads to a loss in 

efficacy of the program as the incentive 

to reduce emissions declines over time. 

Some sources emit at higher levels or 

relax their operation of NOX controls in 

response to the build-up of allowances 

available for compliance, even though 

EPA has concluded those controls are 

necessary to meet the statutory good 

neighbor requirements. This result is 

inconsistent with the statutory mandate 

to ‘‘prohibit’’ significant contribution 

and interference with maintenance of 

the NAAQS in other states, as evidenced 

most clearly in CAA section 126, which 

makes it unlawful for a source ‘‘to 

operate more than three months after [a 

finding that the source emits or would 

emit in violation of the good neighbor 

provision] has been made with respect 


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204The EPA does not believe this adjustment in 

its Step 3 approach for EGUs, or its corresponding, 

improved approach to the trading program at Step 

4—which, again, mimics the effect of permanent 

and enforceable unit-specific emissions limits— 

violates the prohibition on over-control. Our overcontrol analysis is set forth below in Section VI.D 

of this proposed rule, and the EPA proposes to find 

that there is no over-control at the proposed 

stringency (for both EGUs and non-EGUs) in any 

upwind state. 

to it.’’ 42 U.S.C. 7426(c)(2) (emphasis 

added). Moreover, there is no policy 

justification at Step 3 for an upwind 

source to relax or cease operating its 

emissions controls simply because other 

sources of pollution have been reduced. 

In the Revised CSAPR Update, the EPA 

began to address this problem by 

establishing adjusted emissions budgets 

for each year from 2021 through 2025 

based on information about the 

changing EGU fleet known at the time 

of promulgation of the rule. See 86 FR 

23118. As discussed in Section VII.B of 

this proposed rule, the EPA is now 

implementing a more complete 

approach to eliminating significant 

contribution by imposing dynamic 

budget updates and banking restrictions 

to ensure that its selected control 

stringency at Step 3 continues to be 

implemented. 

This approach at Step 4 is wholly 

consistent with EPA’s findings at Step 3. 

This is best illustrated by comparing the 

trading program approach with the 

requirements the EPA could promulgate 

for EGUs based on an approach of 

assigning unit-specific emissions rate 

limitations. Under the latter approach, 

the EPA would assign an enforceable 

emissions rate to each EGU, based on 

the operation of the selected NOX

control strategy (e.g., optimizing 

existing SCRs) that would apply in 

perpetuity. By continually adjusting 

budgets to ensure that emissions 

outcomes are achieved—and downwind 

air quality benefits are delivered—that 

are commensurate with the continuous 

operation of emissions controls at the 

selected control stringency at Step 3, the 

EPA is better aligning the 

implementation of the program at Step 

4 with the level of emissions reductions 

from upwind sources that the EPA has 

determined is appropriate through the 

Step 3 multifactor analysis.204 The EPA 

requests comment on its identified EGU 

control stringencies, including its 

consideration of the cost, air quality 

impacts, and timing of such mitigation 

strategies. 

2. Non-EGU Assessment 

The Agency prepared the non-EGU 

screening assessment for 2026 using the 

analytical framework detailed in Section 

VI.B.2 of this proposed rule. Using a 

$7,500/ton (in 2016 dollars) marginal 

cost threshold identified in the 

framework, the screening assessment 

used CoST with known controls, the 

CMDB, and the 2019 emissions 

inventory and estimated emissions 

reductions from emissions units in the 

Tier 1 industries and impactful boilers 

in the Tier 2 industries. 

Using 2026 as the potential earliest 

date by which controls on emissions 

units in the Tier 1 industries and 

impactful boilers in the Tier 2 industries 

could be installed, the EPA assessed 

whether these emissions reduction 

controls should be required at Step 3 

under its multi-factor test. 

The EPA determined that, for 2026, 

the average air quality improvement at 

receptors relative to the EGU case when 

SCR post-combustion controls were 

installed was 0.18 ppb when Tier 1 nonEGU controls were applied and an 

additional 0.04 ppb when Tier 2 nonEGU controls were applied, based on 

the Step 3 analysis. The EPA 

determined for the purposes of Step 3 

that all but 3 receptors remain 

nonattainment or maintenance after the 

application of these controls, with two 

receptors (one in Brazoria County, Texas 

and one in Kenosha County, Wisconsin) 

switching from maintenance to 

attainment with these non-EGU controls 

in place. 

TABLE VI.D.2–2—AIR QUALITY AT RECEPTORS IN 2026 FROM NON-EGU INDUSTRIES

Monitor ID No. State County 

Average DV 

(ppb) 

Max DV 

(ppb) 

Baseline 

(engineering 

analysis) 

EGU SCR/ 

SNCR 

optimization 

+ LNB 

upgrade + 

SCR/SNCR 

retrofit + nonEGU 

Tier 1 + Tier 2 

Baseline 

(engineering 

analysis) 

EGU SCR/SNCR 

optimization 

+ LNB 

upgrade + SCR/SNCR 

retrofit + non-EGU 

Tier 1 + Tier 2 

40278011 ........................ Arizona ............................ Yuma ............................... 70.11 70.06 71.81 71.76 

80350004 ........................ Colorado .......................... Douglas ........................... 70.94 70.07 71.55 70.67 

80590006 ........................ Colorado .......................... Jefferson ......................... 72.09 71.26 72.69 71.86 

80590011 ........................ Colorado .......................... Jefferson ......................... 72.97 72.16 73.68 72.86 

90010017 ........................ Connecticut ..................... Fairfield ........................... 71.60 71.35 72.30 72.04 

90013007 ........................ Connecticut ..................... Fairfield ........................... 73.09 72.54 73.99 73.43 

90019003 ........................ Connecticut ..................... Fairfield ........................... 74.83 74.40 75.03 74.59 

90099002 ........................ Connecticut ..................... New Haven ..................... 70.77 70.22 72.78 72.21 

170310001 ...................... Illinois .............................. Cook ................................ 69.05 68.73 72.87 72.53 

170310032 ...................... Illinois .............................. Cook ................................ 69.37 69.20 71.98 71.80 

170310076 ...................... Illinois .............................. Cook ................................ 68.75 68.51 71.56 71.31 

170314201 ...................... Illinois .............................. Cook ................................ 69.10 68.83 72.61 72.32 

170317002 ...................... Illinois .............................. Cook ................................ 69.36 68.98 72.27 71.88 

480391004 ...................... Texas .............................. Brazoria ........................... 70.93 68.72 73.09 70.81 

482010024 ...................... Texas .............................. Harris ............................... 76.28 74.23 77.82 75.73 

490110004 ...................... Utah ................................. Davis ............................... 72.20 71.51 74.42 73.70

490353006 ...................... Utah ................................. Salt Lake ......................... 73.00 72.30 74.61 73.90 

490353013 ...................... Utah ................................. Salt Lake ......................... 74.10 73.34 74.60 73.84 

490570002 ...................... Utah ................................. Weber .............................. 70.30 69.63 72.22 71.53 

550590019 ...................... Wisconsin ........................ Kenosha .......................... 72.01 71.57 72.91 72.47 

550590025 ...................... Wisconsin ........................ Kenosha .......................... 68.46 67.95 71.48 70.95 

551010020 ...................... Wisconsin ........................ Racine ............................. 70.52 70.12 72.42 72.02 

Average AQ Change Relative to Base (ppb) ....................................................................................................................................................... 0.64 


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TABLE VI.D.2–2—AIR QUALITY AT RECEPTORS IN 2026 FROM NON-EGU INDUSTRIES—Continued 

Monitor ID No. State County 

Average DV 

(ppb) 

Max DV 

(ppb) 

Baseline 

(engineering 

analysis) 

EGU SCR/ 

SNCR 

optimization 

+ LNB 

upgrade + 

SCR/SNCR 

retrofit + nonEGU 

Tier 1 + Tier 2 

Baseline 

(engineering 

analysis) 

EGU SCR/SNCR 

optimization 

+ LNB 

upgrade + SCR/SNCR 

retrofit + non-EGU 

Tier 1 + Tier 2 

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

For more information about how this 

assessment was performed and the 

results of the analysis for each receptor, 

refer to the Ozone Transport Policy 

Analysis Proposed Rule TSD and to the 

Ozone AQAT included in the docket for 

this rule. 

a. Request for Comment on Non-EGU 

Control Strategies and Measures 

In the non-EGU screening assessment, 

the EPA used CoST, the CMDB, and the 

2019 emissions inventory to assess 

emissions reduction potential from nonEGU emissions units in several 

industries. The EPA identified 

emissions units that were uncontrolled 

or that could be better controlled and 

then applied control technologies to 

estimate emissions reductions and costs. 

As noted previously, the cost estimates 

do not include monitoring, 

recordkeeping, reporting, or testing 

costs. Based on the available 

information, the EPA is proposing to 

require implementation of the non-EGU 

emissions reductions at Step 3 by the 

beginning of the 2026 ozone season. The 

EPA discusses the basis for this 

proposed compliance schedule in 

Section VII.A.2 of this proposed rule. 

The EPA requests comment on certain 

estimates and assumptions in this 

proposal that may affect EPA’s 

evaluation of the capital and annual 

costs of several potential control 

technologies. In particular, the EPA 

requests comment on whether ultra-low 

NOX burners or low NOX burners are 

generally considered part of the process 

or add-on controls for ICI boilers (and 

how process changes or retrofits to 

accommodate controls would affect the 

cost estimates). We request comment on 

our estimates regarding the effectiveness 

of low emissions combustion in 

controlling NOX from RICE compared to 

other potential NOX controls for these 

engines. We request comment on 

whether controls on ICI boilers and 

reciprocating IC engines are likely to be 

run all year (e.g., 8,760 hours/year) or 

only during the ozone season. 

The EPA notes that the non-EGU NOX

mitigation strategy in this proposed rule 

focuses on obtaining emissions 

reductions from non-EGU units that 

were quantitatively determined to have 

the most significant impacts on air 

quality improvements at the downwind 

nonattainment and maintenance 

receptors. However, the EPA requests 

comment on the merits of requiring nonEGU sources within the linked upwind 

states to meet specified technologybased control standards, such as the 

RACT SIP requirements outlined in CFR 

part 51 for non-EGU sources located in 

OTR states. 

3. Combined EGU and Non-EGU 

Assessment 

The EPA used the Ozone AQAT to 

evaluate the combined impact of these 

selected stringency levels for both EGUs 

and non-EGUs on all receptors 

remaining in the 2026 air quality 

modeling base case to inform the overcontrol analysis. EPA’s evaluation 

demonstrated air quality improvement 

at the 22 remaining nonattainment or 

maintenance receptors outside of 

California (see Section V.D of this 

proposed rule for receptor details). The 

EPA estimated that the average air 

quality improvement at these receptors 

relative to the engineering analytics base 

case was 0.64 ppb for emissions 

reductions commensurate with 

optimization of existing SCRs/SNCRs, 

combustion control upgrades, 

application of new post-combustion 

control (SCR and SNCR) retrofits at 

eligible units, and all estimated 

emissions reductions from the Tier 1 

industries and impactful boilers in the 

Tier 2 industries. Table VI.D.1–3 

summarizes the results of EPA’s Step 3 

evaluation of air quality improvements 

at these receptors using AQAT. In 

summary, the collective application of 

these mitigation measures and 

emissions reductions continue to 

deliver downwind air quality 

improvements up until the most 

stringent thresholds identified. The 

health and climate benefits resulting 

from application of these measures (as 

described in the RIA) are estimated to 

exceed the costs, and the identified 

technologies reflect not only 

demonstrated best practices—but 

widely adopted best practices in the 

case of EGU retrofits. 

TABLE VI.D.3–1—CHANGE IN AIR QUALITY REDUCTIONS AT RECEPTORS IN 2026 FROM PROPOSED EGU AND NON-EGU 

EMISSIONS REDUCTIONS abc

Tier/technology 

Ozone season 

emissions 

reductions 

Total PPB 

change across 

all downwind 

receptors d

Average PPB 

change across 

all downwind 

receptors 

EGU (SCR/SNCR optimization + LNB upgrade) + Gen shifting ........................................... 26,250 1.53 0.07 

EGU SCR/SNCR Retrofit + Gen shifting ............................................................................... 63,883 7.89 0.36 

Non-EGU (Tier 1) .................................................................................................................. 41,153 3.89 0.18 

Non-EGU (Tier 2) .................................................................................................................. 6,033 0.82 0.04 

Total ................................................................................................................................ .......................... 14.13 0.64 

Table Notes: 


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205Although 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. 

aAs in prior rules, for the purpose of defining significant contribution at Step 3, the EPA evaluated air quality changes resulting from the application of the emissions reductions in only those states that are linked to each receptor as well as the state containing the receptor. By applying 

reductions to the state containing the receptor, the EPA ensures that it is accounting for the downwind state’s fair share. In addition, this method 

holds each upwind state responsible for its fair share of the downwind problems to which it is linked. Reductions made by other states in order to 

address air quality problems at other receptors do not increase or decrease this share. The air quality impacts on design values that reflect the 

emissions reductions in all linked states and the health and climate benefits from this proposal are discussed in Section IX of this proposed rule. bThe EPA notes that the design values reflected in Tables VI.D.1–1 and 2 correspond to the engineering analysis EGU emissions inventory 

used in AQAT to determine state-level baseline emissions and reductions at Step 3. These tools are discussed in greater detail in the Ozone 

Transport Policy Analysis Proposed Rule TSD. Additionally, these emission reduction values vary slightly from the technology reduction estimates described in Section VI.C, as the values here reflect (1) the sum of the final identified stringency for each state (e.g., SCR retrofit potential 

is not assumed in Alabama, Delaware, and Tennessee), and (2) generation shifting reduction potential identified at each step. cThe total and average ppb results from non-EGUs emissions reductions shown here were generated using the Step 3 AQAT methodology 

consistent with that for EGUs (i.e., including reductions from the state containing the receptor and excluding states that are not explicitly linked to 

particular receptors). The values shown in Table VI.C.2–1 were prepared for the non-EGU screening assessment using a methodology where 

states within the program make emissions reductions for all receptors. States that contain receptors (i.e., Connecticut and Colorado) that are not 

linked to other receptors are not assumed to make reductions under that methodology. dThe cumulative ppb change only shows the aggregate change across all problematic receptors (some of which are located within close proximity to one another) in this part of the Step 3 analysis. Section IX of this proposed rule provides a more complete picture of the air quality impacts of the proposed rule. 

4. Over-Control Analysis 

The EPA applied its over-control test 

to this same set of aggregated EGU and 

non-EGU data described in the previous 

section. As part of the air quality 

analysis using the Ozone AQAT, the 

EPA evaluated potential over-control 

with respect to whether (1) the expected 

ozone improvements would be greater 

than necessary to resolve the downwind 

ozone pollution problem (i.e., beyond 

what is necessary to resolve all 

nonattainment and maintenance 

problems to which an upwind state is 

linked) or (2) the expected ozone 

improvements would reduce the 

upwind state’s ozone contributions 

below the screening threshold (i.e., 1 

percent of the 2015 ozone NAAQS). 

In EME Homer City, the Supreme 

Court held that the EPA cannot 

‘‘require[ ] an upwind State to reduce 

emissions by more than the amount 

necessary to achieve attainment in every 

downwind State to which it is linked.’’ 

572 U.S. at 521. On remand from the 

Supreme Court, the D.C. Circuit held 

that this means that the EPA might 

overstep its authority ‘‘when those 

downwind locations would achieve 

attainment even if less stringent 

emissions limits were imposed on the 

upwind States linked to those 

locations.’’ EME Homer City II, 795 F.3d 

at 127. The D.C. Circuit qualified this 

statement by noting that this ‘‘does not 

mean that every such upwind state 

would then be entitled to less stringent 

emissions limits. Some of those upwind 

States may still be subject to the more 

stringent emissions limits so as not to 

cause other downwind locations to 

which those States are linked to fall into 

nonattainment.’’ Id. at 14–15. As the 

Supreme Court explained, ‘‘while EPA 

has a statutory duty to avoid overcontrol, the Agency also has a statutory 

obligation to avoid ‘under-control,’ i.e., 

to maximize achievement of attainment 

downwind.’’ 572 U.S. at 523. The Court 

noted that ‘‘a degree of imprecision is 

inevitable in tackling the problem of 

interstate air pollution’’ and that 

incidental over-control may be 

unavoidable. Id. ‘‘Required to balance 

the possibilities of under-control and 

over-control, EPA must have leeway in 

fulfilling its statutory mandate.’’ Id.205

Consistent with these instructions 

from the Supreme Court and the D.C. 

Circuit, using the Ozone AQAT, the 

EPA first evaluated whether reductions 

resulting from the selected control 

stringencies for EGUs in 2023 and 2026 

combined with the emissions reductions 

selected for non-EGUs in 2026 can be 

anticipated to resolve any downwind 

nonattainment or maintenance problems 

(see the Ozone Policy Analysis 

Proposed Rule TSD for details on the 

construction and application of AQAT). 

The control stringency selected for 2023 

(a representative cost threshold of 

$1,800 per ton for EGUs) includes 

emissions reductions commensurate 

with optimization of existing SCRs and 

SNCRs and installation of state-of-theart combustion controls, which are 

estimated to change the status of one 

maintenance receptor, shifting the Clark 

County, Nevada monitor to attainment 

in 2023. However, no other 

nonattainment or maintenance problems 

would be resolved in 2023 with this 

level of stringency, and no state is 

linked solely to this receptor. Nor do 

any states’ contribution levels drop 

below the 1% of NAAQS threshold. 

Thus, the EPA determined that none of 

the 26 linked states have all of their 

linkages resolved at the proposed EGU 

level of control stringency in 2023, and 

hence, the EPA finds no over-control in 

the proposed level of stringency. 

Based on the air quality baseline 

modeling for 2026, all receptors to 

which Alabama, Delaware, and 

Tennessee are linked in 2023 are 

projected to be in attainment in 2026. 

Therefore, no additional emissions 

reductions are proposed for EGUs or 

non-EGUs in those states beyond the 

2023 level of stringency. For the 

remaining 23 states, the selected control 

stringency (at a representative cost per 

ton threshold of $11,000 for EGUs and 

a marginal cost threshold of $7,500 for 

non-EGUs) beginning in 2026 includes 

additional EGU controls and estimated 

non-EGU emissions reductions for Tier 

1 and Tier 2 non-EGU industries. The 

EPA used the Ozone AQAT to evaluate 

the impact of this selected stringency 

level (as well as other potential 

stringency levels) on all receptors 

remaining in the 2026 air quality 

modeling base case. This assessment 

shows that the selected control 

stringency level and emissions 

reductions are estimated to change the 

status of three maintenance receptors to 

attainment in 2026—Douglas County, 

Colorado; Brazoria County, Texas; and 

Kenosha County, Wisconsin. Based on 

these data, EPA proposes that at least 20 

of the 23 states continue to be linked to 

nonattainment or maintenance receptors 

after implementation of all identified 

Step 3 reductions, and hence, the EPA 

finds no over-control in its 

determination of that level of stringency 

for those 20 states. 

For 2 of the 23 states, Arkansas and 

Mississippi, the last downwind receptor 

to which these two states are linked (i.e., 

Brazoria County, Texas) is estimated to 

achieve attainment and maintenance 

after full application of EGU reductions 

and Tier 1 non-EGU reductions. This 

suggests application of the estimated 

non-EGU emissions reductions from 

Tier 2 may constitute over-control for 

these states. However, this downwind 


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206 In this proposal, the EPA continues to assume, 

as it has in prior transport rules, that home-states 

(that are not otherwise linked) will make similar 

reductions as those assumed in this action for 

purposes of local attainment. While the EPA 

continues to view this to be an equitable means of 

assessing air quality improvement from good 

neighbor actions, because the downwind receptor 

state is assumed to do its ‘‘fair share,’’ the EPA 

recognizes that recent case law has called the need 

for such an assumption into question, and thus 

using this assumption as a basis for finding overcontrol may be inappropriate. In Maryland, the EPA 

had argued that good neighbor obligations should 

not be required by the Marginal area attainment 

deadline in part because ‘‘marginal nonattainment 

areas often achieve the NAAQS without further 

downwind reductions, so it would be unreasonable 

to impose reductions on upwind sources based on 

the next marginal attainment deadline.’’ 958 F.3d 

1185, 1204. The D.C. Circuit rejected that argument, 

noting regulatory consequences for the downwind 

state for failure to attain even at the Marginal date, 

and, citing Wisconsin, the court held that upwind 

sources violate the good neighbor provision if they 

significantly contribute even at the Marginal area 

attainment date. Id. Thus, the EPA examines overcontrol in this proposal with and without this 

assumption of home-state emission reductions. 

receptor only resolves by a small margin 

after the application of all EGU and Tier 

1 non-EGU emissions reductions. The 

EPA anticipates that updates to 

emissions inventories, emissions 

reduction potential from identified 

technologies, or the over-control test 

methodology resulting from comments 

or other updated information could 

possibly move this site back into 

nonattainment- or maintenance-receptor 

status when the EPA conducts an overcontrol analysis prior to finalizing this 

proposal. 

For 1 of the 23 states, Wyoming, the 

EPA also notes a potential over-control 

finding under the methodological 

assumption where emissions reductions 

of commensurate stringency are 

assumed in the downwind state of 

Colorado (which is not subject to this 

proposal). As demonstrated in the 

Ozone Transport Policy Analysis 

Proposed Rule TSD, the last downwind 

receptor for Wyoming (i.e., Douglas 

County, Colorado) is estimated to 

achieve attainment and maintenance 

after full application of EGU reductions. 

This suggests application of estimated 

non-EGU emissions reductions from 

Tier 1 and Tier 2 industries may 

constitute over-control for this state. 

However, when the assumption of 

commensurate downwind state 

reductions in Colorado is removed from 

the methodology, the downwind 

receptor to which Wyoming is linked 

does not resolve and there is no 

identified over-control estimated for 

Wyoming.206

Next, the EPA evaluated the potential 

for over-control with respect to the 1 

percent of the NAAQS threshold 

applied in this proposed rulemaking at 

Step 3 of the good neighbor framework, 

assessed for the selected control 

stringencies for each state for each 

period that downwind nonattainment 

and maintenance problems persist (i.e., 

2023 and 2026). Specifically, the EPA 

evaluated whether the selected control 

stringencies would reduce upwind 

emissions to a level where the 

contribution from any of the 26 linked 

states in 2023 or 23 linked states in 2026 

would be below the 1 percent threshold. 

The EPA finds that for the mitigation 

measures assumed in 2023 and in 2026, 

all states that contributed greater than or 

equal to the 1 percent threshold in the 

base case continued to contribute 

greater than or equal to 1 percent of the 

NAAQS to at least one remaining 

downwind nonattainment or 

maintenance receptor for as long as that 

receptor remained in nonattainment or 

maintenance. In the case of Arkansas, 

Mississippi, and Wyoming, while their 

linkages resolved based on a change in 

receptor status at Step 1 (as discussed 

above), their contribution to the relevant 

monitoring sites remained above 1 

percent of the NAAQS, and thus, the 

potential basis for an over-control 

finding with respect to these states is 

not based on their contribution 

dropping below 1 percent of the 

NAAQS at those sites. For more 

information about this assessment, refer 

to the Ozone Transport Policy Analysis 

Proposed Rule TSD and the Ozone 

AQAT. 

Based on these results, under no 

scenario does EPA’s AQAT analysis for 

this proposal indicate that including all 

identified EGU reductions would 

constitute over-control. Rather, if these 

results hold for a final rule, the potential 

over-control for Arkansas and 

Mississippi can be avoided by not 

requiring Tier 2 non-EGU reductions, 

and over-control for Wyoming can be 

avoided by not requiring any non-EGU 

reductions. 

Nonetheless, while acknowledging 

these preliminary analytic results, the 

EPA is proposing that all of the selected 

EGU and non-EGU NOX reduction 

strategies selected in EPA’s Step 3 

analysis be applied to all linked states 

in 2026—including to Arkansas, 

Mississippi, and Wyoming—to 

eliminate significant contribution to 

nonattainment and interference with 

maintenance of the 2015 ozone NAAQS. 

The Supreme Court has directed the 

EPA to avoid both over-control and 

under-control in addressing good 

neighbor obligations. In addition, the 

D.C. Circuit has reinforced that overcontrol must be established based on 

particularized, record evidence on an 

as-applied basis. As noted previously, 

even slight changes in analytics based 

on comments or new information 

between proposal and final could result 

in the Brazoria, Texas site remaining 

either a nonattainment or maintenance 

receptor. Further, with respect to 

Wyoming, its linkage only resolves 

based on an unenforceable assumption 

regarding a certain level of emissions 

reduction in Colorado. The proposed 

determination that the stringency of this 

proposal does not constitute overcontrol for any linked state is further 

reinforced by EPA’s observation in 

Section IV.A.1 of this proposed rule 

regarding the nature of ozone, and in 

particular, that future ozone 

concentrations and the formation of 

ground level ozone, may be impacted by 

climate change in future years. 

Under these circumstances, the EPA 

cannot conclude based on the current 

record that any aspect of its selected 

Step 3 level of control stringency 

constitutes unnecessary over-control for 

any of the 23 states found to be linked 

in 2026. The EPA requests comment on 

this proposed conclusion. The EPA 

requests comment on an alternative 

conclusion that, if this same analysis 

were to persist for a final rule, it must 

limit non-EGU reduction requirements 

for Arkansas and Mississippi to only the 

Tier 1 industries, and for Wyoming to 

limit the stringency of the rule to only 

the EGU reduction strategies. 

VII. Implementation of Emissions 

Reductions 

A. NOX Reduction Implementation 

Schedule 

This proposal, if finalized, will ensure 

that emissions reductions necessary to 

eliminate significant contribution will 

be achieved as ‘‘as expeditiously as 

practicable’’ as required under CAA 

section 181(a). The EPA’s anticipated 

timing will provide for all possible 

emissions reductions to go into effect 

beginning in the 2023 ozone season, 

which is aligned with the next 

upcoming attainment date of August 3, 

2024, for areas classified as Moderate 

nonattainment under the 2015 ozone 

standard. Additional emissions 

reductions that the EPA finds not 

possible to implement by that 

attainment date are proposed to take 

effect as expeditiously as practicable, 

with the full suite of emissions 

reductions taking effect by the 2026 

ozone season, which is aligned with the 

August 3, 2027, attainment date for 

areas classified as Serious 

nonattainment under the 2015 ozone 

NAAQS. This schedule of emissions 

reductions meets the requirement in the 

Good Neighbor Provision that it must be 


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207North 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). 

208North Carolina, 531 F.3d at 911–913. 

209Wisconsin, 938 F. 3d at 303, 3018–20. 

210 Maryland, 958 F.3d at 1203–1204. Similarly, 

in New York v. EPA, 964 F.3d 1214 (D.C. Cir. 2020), 

the Court found the EPA’s selection of a 2023 

analysis year in evaluating New York’s section 126 

petition unlawful in light of the New York 

Metropolitan Area’s 2021 Serious area deadline for 

attaining the 2008 ozone NAAQS. 964 F.3d at 1226 

(citing Wisconsin and Maryland). 

211Wisconsin, 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). 212 86 FR 23093. 

implemented ‘‘consistent with the 

provisions of [title I of the CAA.]’’ CAA 

section 110(a)(2)(D)(i). Finally, the 

timing of this proposed rulemaking is 

designed to achieve reductions as 

expeditiously as practicable while 

adhering to the procedural requirements 

of CAA section 110. The EPA proposes 

this rule to constitute a full remedy for 

interstate transport for the 2015 ozone 

NAAQS for the states covered by this 

proposal; the EPA does not anticipate 

further rulemaking to address good 

neighbor obligations will be required for 

these states with the finalization of this 

rule. 

EPA’s proposed determinations 

regarding the timing of this proposed 

rule are informed by and in compliance 

with several recent court decisions. The 

D.C. Circuit has reiterated several times 

since 2008 that, under the terms of the 

Good Neighbor Provision, upwind states 

must eliminate their significant 

contributions to downwind areas 

‘‘consistent with the provisions of [title 

I of the Act],’’ including those 

provisions setting attainment deadlines 

for downwind areas.207 In North 

Carolina, the D.C. Circuit found the 

2015 compliance deadline that the EPA 

had established in CAIR unlawful in 

light of the downwind nonattainment 

areas’ 2010 deadline for attaining the 

1997 NAAQS for ozone and PM2.5.208

Similarly, in Wisconsin, the Court found 

the CSAPR Update unlawful to the 

extent it allowed upwind states to 

continue their significant contributions 

to downwind air quality problems 

beyond the downwind states’ statutory 

deadlines for attaining the 2008 ozone 

NAAQS.209 More recently, in Maryland, 

the Court found the EPA’s selection of 

a 2023 analysis year in evaluating state 

petitions submitted under CAA section 

126 unlawful in light of the downwind 

Marginal nonattainment areas’ 2021 

deadline for attaining the 2015 ozone 

NAAQS.210 The Court noted in 

Wisconsin that the statutory command— 

that compliance with the Good 

Neighbor Provision must be achieved in 

a manner ‘‘consistent with’’ title I of the 

CAA—may be read to allow for some 

deviation from the mandate to eliminate 

prohibited transport by downwind 

attainment deadlines, ‘‘under particular 

circumstances and upon a sufficient 

showing of necessity,’’ but concluded 

that ‘‘[a]ny such deviation would need 

to be rooted in Title I’s framework’’ and 

would need to ‘‘provide a sufficient 

level of protection to downwind 

States.’’ 211

1. 2023–2025: EGU NOX Reductions 

Beginning in 2023 

The near-term EGU control 

stringencies and corresponding 

reductions in this proposed rulemaking 

cover the 2023, 2024, and 2025 ozone 

seasons. This is the period in which 

some reductions will be available, but 

the large portion of full remedy 

reductions—mainly those reductions 

that are driven by post combustion 

control installation—identified in 

Sections VI.B through VI.D of this 

proposed rule are not yet available. The 

EGU NOX mitigation strategies available 

during these initial 3 years are the 

optimization of existing postcombustion controls (SCRs and SNCRs) 

and combustion control upgrades. As 

described in Sections VI.B through VI.D 

of this proposed rule and in 

accompanying TSDs, these mitigation 

measures can be implemented in under 

two months in the case of existing 

control optimization and in 6 months in 

the case of combustion control 

upgrades. 

As described in Section VI.B of this 

proposed rule and in the identified 

TSDs, these timing assumptions account 

for planning, procurement, and any 

physical or structural modification 

necessary. The EPA provides significant 

historical data, including the 

implementation of the most recent 

Revised CSAPR Update, as well as 

engineering studies and input factor 

analysis documenting the feasibility of 

these timing assumptions. However, 

these timing assumptions are 

representative of fleet averages, and the 

EPA has noted that some units will 

likely overperform their installation 

timing assumptions, while others may 

have unit configuration or operational 

considerations that result in their 

underperforming these timing 

assumptions. As in prior interstate 

transport rules, the EPA is 

implementing these EGU reductions 

through a trading program approach. 

The trading program’s option to buy 

additional allowances provides 

flexibility in the program for outlier 

sources that may need more time than 

what is representative of the fleet 

average to implement these mitigation 

strategies while providing an economic 

incentive to outperform rate and timing 

assumptions for those sources that can 

do so. In effect, this trading program 

implementation operationalizes the 

mitigation measures as state-wide 

assumptions for the EGU fleet rather 

than unit-specific assumptions. 

However, starting in 2024, as 

described in Section VII.B.7 of this 

proposed rule, unit-specific daily 

emissions rate limits are applied to coal 

units with existing SCR at a level 

consistent with operating that control. 

The EPA believes that implementing 

these emissions reductions at the state 

level starting in 2023 (through state 

emissions budgets) while imposing the 

unit-specific emissions rate limits in 

2024 achieves the necessary 

environmental performance as soon as 

possible while accommodating any 

heterogeneity in unit-level 

implementation schedules regarding 

daily operation of optimized SCRs. 

Additionally, as in prior rules, the 

EPA assumes combustion control 

upgrade implementation may take up to 

6 months. In the Revised CSAPR 

Update, covering 12 of the 25 states for 

which emissions reduction 

requirements for EGUs are established 

under this proposed action, the EPA 

finalized the rule in March of 2021 and 

thus did not require these combustion 

control-based emissions reductions in 

ozone-season state emissions budgets 

until 2022 (year two of that program).212

The EPA is applying the same timing 

assumption regarding combustion 

control upgrades for this proposed 

rulemaking given the expected similar 

window between an anticipated final 

action date and the start of the year one 

ozone season. The EPA is not assuming 

the implementation of any additional 

combustion control upgrades in state 

emissions budgets until 2024. Therefore, 

those 13 states covered in this action for 

EGU emissions reductions that were not 

covered in the Revised CSAPR Rule 

have 2023 emissions budgets that only 

reflect optimization of existing controls. 

Any identified combustion control 

upgrade emissions reductions are 

reflected beginning in the 2024 ozoneseason budgets for these states. For the 

12 states covered under the Revised 

CSAPR Update, any identified 

emissions reduction potential from 

combustion control upgrade was 

included and reflected in those state 

budgets beginning in 2022 under the 

Revised CSAPR Update. Therefore, the 


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213For 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). 

214CAA 110(a)(2)(D)(i) and 126(c). 

215See, e.g., 40 CFR 51.1112(a)(3) and 

51.1312(a)(3)(i) (requiring implementation of RACT 

required pursuant to initial nonattainment area 

designations no later than January 1 of the fifth year 

after the effective date of designation, which is less 

than 3 years after the submission deadline under 40 

CFR 51.1112(a)(2)) and 51.1312(a)(2)(i), 

respectively). 

216 40 CFR 51.1312(a)(2)(i) (requiring submission 

of RACT SIP revisions no later than 24 months after 

the effective date of designation) and 

51.1312(a)(3)(i) (requiring implementation of RACT 

SIP revisions as expeditiously as practicable, but no 

later than January 1 of the fifth year after the 

effective date of designation). For reclassified areas, 

states must implement RACT SIP revisions as 

expeditiously as practicable, but no later than the 

start of the attainment year ozone season associated 

with the area’s new attainment deadline, or January 

1 of the third year after the associated SIP revision 

submittal deadline, whichever is earlier; or the 

deadline established by the Administrator in the 

final action issuing the area reclassification. 40 CFR 

51.1312(a)(3)(ii); see also 83 FR 62989, 63012– 

63014. 

217 40 CFR 51.1312(a)(2)(i) (requiring submission 

of RACT SIP revisions no later than 24 months after 

the effective date of designation). 

218See, 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. 

EPA is assuming that this combustion 

control upgrade potential is available, if 

not already realized, by the first year of 

this action (i.e., 2023) in this proposed 

rule. 

2. 2026 and Later Years: EGU and NonEGU NOX Reductions Beginning in 2026 

In accordance with the good neighbor 

provision and the downwind attainment 

schedule under CAA section 181 for the 

2015 ozone NAAQS, the EPA is 

proposing to align its analysis and 

implementation of the emissions 

reductions addressing significant 

contribution from EGU and non-EGU 

sources that require relatively longer 

lead time at a sectoral scale with the 

2026 ozone season, which is the last full 

ozone season preceding the August 3, 

2027, Serious area attainment date for 

the 2015 ozone NAAQS.213 The EPA 

proposes to find that this compliance 

deadline is the most expeditious date 

practicable and would achieve the 

required emissions reductions prior to 

the next applicable attainment date by 

which such reductions are, in fact, 

possible. The EPA proposes to find that 

it is not possible to require 

implementation of all necessary 

emissions controls across all of the 

affected EGU and non-EGU sources by 

the August 3, 2024, Moderate area 

attainment date. 

Thus, the EPA is proposing to require 

compliance with the control 

requirements for all non-EGUs and the 

EGU reductions related to postcombustion control retrofit identified in 

this section no later than the 2026 ozone 

season (May through September). If 

finalized in early 2023, the final rule 

would provide more than three years for 

EGU and non-EGU sources to install 

whatever controls they deem suitable to 

comply with required emissions 

reductions by the 2026 ozone season. In 

addition, the publication of this 

proposal provides roughly an additional 

year of notice to these source owners 

and operators that they should begin 

engineering and financial planning now 

to be prepared to meet this 

implementation timetable. 

The EPA views this timeframe for 

retrofitting post-combustion NOX

emissions controls and other non-EGU 

controls to be presumptively reasonable 

and achievable. A 3-year period for 

installation of post-combustion control 

technologies is consistent with the 

statutory timeframe for implementation 

of the controls required to address 

interstate pollution under section 

110(a)(2)(D) and 126 of the Act, the 

statutory timeframes for implementation 

of RACT in ozone nonattainment areas 

classified as Moderate or above, and 

other statutory provisions that establish 

control requirements for existing 

stationary sources of pollution. 

For example, section 126 of the CAA 

authorizes a downwind state or tribe to 

petition the EPA for a finding that 

emissions from ‘‘any major source or 

group of stationary sources’’ in an 

upwind state contribute significantly to 

nonattainment in, or interfere with 

maintenance by, the downwind state. If 

the EPA makes a finding that a major 

source or a group of stationary sources 

emits or would emit pollutants in 

violation of the relevant prohibition in 

CAA section 110(a)(2)(D), the source(s) 

must shut down within 3 months from 

the finding unless the EPA directly 

regulates the source(s) by establishing 

emissions limitations and a compliance 

schedule extending no later than three 

years from the date of the finding, to 

eliminate the prohibited interstate 

transport of pollutants as expeditiously 

as practicable.214 Thus, in the provision 

that allows for direct federal regulation 

of sources violating the good neighbor 

provision, Congress established 3 years 

as the maximum amount of time 

available from a final action to when 

emissions reductions need to be 

achieved at the relevant source or group 

of sources. 

Additionally, for ozone 

nonattainment areas classified as 

Moderate or higher, the CAA requires 

states to implement RACT requirements 

less than three years after the statutory 

deadline for submitting these measures 

to the EPA.215 Specifically, for these 

areas, CAA sections 182(b)(2) and 182(f) 

require that states implement RACT for 

existing VOC and NOX sources as 

expeditiously as practicable but no later 

than May 31, 1995, approximately 30 

months after the November 15, 1992, 

deadline for submitting RACT SIP 

revisions. For purposes of the 2015 

ozone NAAQS, the EPA has interpreted 

these provisions to require 

implementation of RACT SIP revisions 

as expeditiously as practicable but no 

later than January 1 of the fifth year after 

the effective date of designation, which 

is less than 3 years after the deadline for 

submitting RACT SIP revisions.216 For 

areas initially designated nonattainment 

with a Moderate or higher classification 

effective August 3, 2018 (83 FR 25776), 

that implementation deadline falls on 

January 1, 2023, approximately 29 

months after the August 3, 2020 

submission deadline.217 Moderate ozone 

nonattainment areas must also 

implement all reasonably available 

control measures (including RACT) 

needed for expeditious attainment 

within three years after the statutory 

deadline for states to submit these 

measures to the EPA as part of a 

Moderate area attainment 

demonstration.218

The EPA notes that the types and 

sizes of the EGU and non-EGU sources 

that the EPA proposes to include in this 

proposed rule, as well as the types of 

emissions control technologies on 

which the EPA proposes to base the 


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219See the Non-EGU Sectors TSD for a discussion 

of SIP-approved RACT rules in effect in downwind 

states. 

220CAA section 112(i)(3)(B) generally authorizes 

the EPA to grant an extension of up to 1 additional 

year for an existing source to comply with 

emissions standards ‘‘if such additional period is 

necessary for the installation of controls,’’ and 

sections 112(i)(4) through (8) provide for limited 

extensions granted by the President where certain 

conditions are met, for existing sources that have 

installed the best available control technology 

(BACT) or technology required to meet a lowest 

achievable emissions rate (LAER), and for new 

sources for which construction or reconstruction is 

commenced by certain dates. 

221 958 F.3d at 1203–1204 (remanding the EPA 

denial of section 126 petition based on the EPA 

analysis of downwind air quality in 2023 rather 

than 2021, the year containing the Marginal area 

attainment date). 

222CAA sections 110(a)(1) and 110(a)(2)(D)(i) 

(requiring states to submit, within 3 years after 

EPA’s promulgation of a new or revised NAAQS, 

SIP provisions adequate to satisfy the Good 

Neighbor Provision). As the Supreme Court noted 

in EME Homer City I, ‘‘nothing in the statute places 

EPA under an obligation to provide specific metrics 

to States before they undertake to fulfill their good 

neighbor obligations.’’ 572 U.S. 489, 510. 

223 938 F.3d at 317–318. For example, the court 

observed that the EPA may shorten the deadline for 

SIP submissions under CAA section 110(a)(1) and 

may issue FIPs soon thereafter under CAA section 

110(c)(1), to align the upwind states’ deadline for 

satisfying good neighbor obligations with the 

downwind states’ deadline for attaining the 

NAAQS. Id. at 318. 

224 Id. at 316 and 319–320 (noting that any such 

deviation must be ‘‘rooted in Title I’s framework’’ 

and ‘‘provide a sufficient level of protection to 

downwind States’’). 

225Compliance by the August 3, 2021, Marginal 

area attainment date is also impossible as that date 

has passed. 

226See 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. 

emissions limitations that would take 

effect for the 2026 ozone season, 

generally are intended to be consistent 

with the scope and stringency of RACT 

requirements for existing major sources 

of NOX in downwind Moderate 

nonattainment areas and some upwind 

areas, which many states have already 

implemented in their SIPs.219 Thus, the 

timing Congress allotted for sources in 

downwind states to come into 

compliance with RACT requirements 

bears directly on the amount of time 

that should be allotted here and 

indicates, as does CAA section 126, that 

3 years is an outer limit on the time that 

should be given sources to come into 

compliance. 

Finally, with respect to emissions 

standards for hazardous air pollutants, 

section 112(i)(3) of the CAA requires the 

EPA to establish compliance dates for 

each category or subcategory of existing 

sources subject to an emissions standard 

that ‘‘provide for compliance as 

expeditiously as practicable, but in no 

event later than 3 years after the 

effective date of such standard,’’ with 

limited exceptions.220 Here again, where 

Congress was concerned with 

addressing emissions of pollutants that 

impact public health, a 3-year time 

period was allotted as the time needed 

for existing sources to come into 

compliance. 

All of these statutory timeframes for 

implementation of new control 

requirements on existing stationary 

sources indicate that Congress 

considered 3 years to be not only a 

sufficient amount of time but a 

maximum amount of time allowable for 

existing stationary sources to install 

pollution controls as necessary for 

expeditious attainment, to eliminate 

prohibited interstate transport of 

pollutants, and to protect public health. 

Further, the EPA notes that, given the 

number of years that have passed since 

EPA’s promulgation of the 2015 ozone 

NAAQS and related nonattainment area 

designations in 2018, and in light of the 

Maryland court’s holding that good 

neighbor obligations for the 2015 ozone 

NAAQS should have been implemented 

by the Marginal area attainment date in 

2021,221 many states are substantially 

delayed in implementing their good 

neighbor obligations for these NAAQS, 

and the sources proposed for NOX

emissions control in this rule have 

continued to operate for several years 

without the controls necessary to 

eliminate their significant contribution 

to ongoing and persistent ozone 

nonattainment and maintenance 

problems in other states. Under these 

circumstances, we find it more than 

reasonable to require compliance with 

the control requirements for all nonEGUs and the EGU reductions related to 

post-combustion control retrofit 

identified in Section VI.B.1.b of this 

proposed rule by the beginning of the 

2026 ozone season (i.e., by May 1, 

2026). May 1, 2026, is more than 3 years 

after the date by which the EPA 

currently anticipates promulgating a 

final FIP for the covered states, more 

than three years after the January 1, 

2023, deadline for implementation of 

section 182 RACT SIP provisions in 

areas classified as Moderate or higher, 

and almost 8 years after the October 1, 

2018, deadline for submission of good 

neighbor SIPs that prohibit significant 

contribution to nonattainment or 

interference with maintenance in 

downwind states.222

As the D.C. Circuit noted in 

Wisconsin, the good neighbor provision 

requires upwind states to ‘‘eliminate 

their substantial contributions to 

downwind nonattainment in concert 

with the attainment deadlines’’ in the 

downwind states, even where those 

attainment deadlines occur before EPA’s 

statutory deadline to promulgate a 

FIP.223 Referencing the Supreme Court’s 

description of the attainment deadlines 

as ‘‘the heart’’ of the CAA, the 

Wisconsin court noted that some 

deviation from the mandate to eliminate 

prohibited transport by downwind 

attainment deadlines may be allowed 

only ‘‘under particular circumstances 

and upon a sufficient showing of 

necessity,’’ e.g., when compliance with 

the statutory mandate amounts to an 

impossibility.224

For the reasons provided below in 

this section, the EPA is proposing to 

find that installation of certain EGU 

controls and all non-EGU controls is not 

possible by the Moderate area 

attainment date for the 2015 ozone 

NAAQS (i.e., August 3, 2024),225 and 

that the 2026 ozone season, which 

corresponds to the August 3, 2027, 

Serious area attainment date for these 

NAAQS, is the earliest downwind 

attainment date by which the required 

emissions reductions from these 

strategies are possible. 

a. EGU Schedule for 2026 and Later 

Years 

As discussed in Sections VI.B through 

VI.D of this proposed rule, significant 

emissions reduction potential exists and 

is included in EPA’s quantification of 

significant contribution based on the 

potential to install post-combustion 

controls (SCR and SNCRs) at EGUs. 

However, as discussed in detail in those 

sections, the assumption for installation 

of this technology on a region-wide 

scale is 36 months in this proposed rule. 

This amount of time allows for all 

necessary procurement, permitting, and 

installation milestones across multiple 

units in the covered region. Therefore, 

the EPA proposes to find that these 

emissions reductions are not available 

any earlier than the 2026 compliance 

period. For each year in 2026 and 

beyond, state emissions budgets include 

reductions commensurate with these 

post-combustion control technologies 

identified for covered units in Step 3. 

The EPA notes that similar compliance 

schedules and post-combustion control 

retrofit installations have been realized 

successfully in prior programs allowing 

similar timeframes. Subsequent to the 

NOX SIP Call and the parallel Finding 

of Significant Contribution and 

Rulemaking on Section 126 Petitions 

(which became effective December 28, 

1998, and February 17, 2000, 

respectively 226), nearly 19 GW of SCR 


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227However, as discussed in Section VII.B.1.c.i of 

this proposed rule, EPA’s determinations in this 

regard are not based on a finding that the retrofit 

of post-combustion controls would not be feasible 

in the 2026 ozone season for all relevant units. The 

EPA finds that such retrofits are available and 

feasible on a fleetwide scale starting in the 2026 

ozone season. 

228Final Technical Support Document (TSD) for 

the Final Cross-State Air Pollution Rule for the 2008 

Ozone NAAQS, Assessment of Non-EGU NOX

Emissions Controls, Cost of Controls, and Time for 

Compliance Final TSD (‘‘CSAPR Update Non-EGU 

TSD’’), August 2016 (Table 3), available at https:// 

www.epa.gov/csapr/assessment-non-egu-NOXemission-controls-cost-controls-and-timecompliance-final-tsd. See also Institute of Clean Air 

Companies, SNCR Committee, ‘‘White Paper, 

Selective Non-Catalytic Reduction (SNCR) For 

Controlling NOX Emissions,’’ at 5 (noting that 

‘‘SNCR retrofits typically do not require extended 

source shutdowns’’). 229 63 FR 57356, 57448 (October 27, 1998). EPA 

generally anticipates that any required permitting 

processes may run concurrent with other steps in 

the installation processes and thus may not 

significantly lengthen the total time needed for 

installation. 230 Id. at 57447–57449. 231 Id. at 57447, 57449. 232 Id. at 57448. 

233 Id. 

234 Id. 

235 Id. 

236 Id. at 57449. 

237 Id. at 57448 (Table V–1 and Table V–2). 

238See Final Report, ‘‘Engineering and Economic 

Factors Affecting the Installation of Control 

Technologies for Multipollutant Strategies,’’ EPA– 

600/R–02/073 (October 2002). 

retrofit came online in 2002 and another 

42 GW of SCR retrofit came online for 

steam boilers in 2003, illustrating that a 

considerable volume of SCR retrofit 

capacity is possible in a 36 month 

period. 

However, the EPA is not proposing to 

apply daily emissions rates on coal-fired 

steam EGUs assumed to retrofit SCR 

until 2027 (as described in Section 

VII.B.1.c.i of this proposed rule). The 

EPA believes that implementing these 

emissions reductions at the state level 

starting in 2026 (through state emissions 

budgets) while imposing the unitspecific emissions rate limits in 2027 

achieves the necessary environmental 

performance as soon as possible while 

accommodating any heterogeneity in 

unit-level implementation schedules 

regarding installation of new SCR.227

b. Non-EGU Schedule for 2026 and 

Later Years 

For the suite of non-EGU controls on 

which the EPA has based its Step 3 

findings as described in Section VI of 

this proposed rule, the EPA proposes to 

require that these controls be installed 

and operational by the 2026 ozone 

season and to find that any earlier date 

is not possible. The EPA previously 

examined the time necessary to install 

the controls identified for several nonEGU industries. Although the 

information on installation times for 

most NOX controls applied to glass and 

cement manufacturing was uncertain, 

the EPA identified minimum estimated 

installation times for a number of other 

non-EGU source categories that ranged 

from several weeks to slightly over a 

year. This included timeframes of 42–51 

weeks for SNCR applied to dry cement 

manufacturing facilities and cement 

kilns/dryers burning bituminous coal, 

28–58 weeks for SCR applied to boilers 

and process heaters, 28–58 weeks for 

SCR applied to iron and steel in-process 

combustion, and 6–8 months for low 

NOX burners and flue gas recirculation 

at iron and steel mills.228 Taking into 

account necessary scale-up of 

construction services for multiple 

control installations at several emissions 

units, the time needed to have NOX

monitoring installed and operating, and 

other necessary steps in the permitting 

and construction processes (e.g., review 

of vendor bids), the EPA estimates an 

additional period of 6 to 18 months may 

be necessary for existing non-EGU 

sources to install the necessary controls, 

depending on the number of control 

installations at a facility.229

Additionally, the EPA previously 

considered the installation timing needs 

for NOX controls (including SCR, SNCR, 

and combustion controls) at both EGU 

and non-EGU sources as part of the 1998 

NOX SIP Call.230 With respect to 

combustion controls (e.g., low-NOX

burners, overfire air, etc.), the EPA 

found that sources should be able to 

complete control technology 

installations and obtain relevant permits 

in relatively short timeframes given 

considerable experience at that time 

among sources and permitting agencies 

with the implementation of such 

controls, the fact that combustion 

controls are constructed of commonly 

available materials (steel, piping, etc.) 

and do not require reagent during 

operation, and the then availability of 

many vendors of combustion control 

technology.231

With respect to post-combustion 

controls (primarily SCR and SNCR), the 

EPA considered three basic factors in 

assessing installation timing needs: (1) 

Availability of materials and labor, (2) 

the time needed to implement controls 

at plants with single or multiple retrofit 

requirements, and (3) the potential for 

interruptions in power supply resulting 

from outages needed to complete 

installations on EGUs.232 Assuming 

adequate supplies of both off-the-shelf 

hardware (such as steel, piping, nozzles, 

pumps, and related equipment) and the 

catalyst used in the SCR process, as well 

as sufficient vendor capacity to supply 

retrofit SCR catalyst to sources, and 

taking into account the additional time 

needed for facility engineering review, 

developing control technology 

specifications, awarding a procurement 

contract, obtaining a construction 

permit, completing control technology 

design, installation, and testing, and 

obtaining an operating permit, the EPA 

found that (a) about 21 months would 

be needed to implement an SCR retrofit 

on a single unit and (b) about 19 months 

would be needed to implement an 

SNCR retrofit on a single unit.233 The 

EPA also examined several particularly 

complicated implementation efforts and 

found that 34 months would be needed 

for a plant to install a maximum of 6 

SCRs while 24 months would be needed 

for a plant to install a maximum of 10 

SNCRs.234 Finally, the EPA found that 

the necessary controls could be installed 

on EGUs without any disruptions in the 

supply of electricity because 

connections between a NOX control 

system and a boiler can generally be 

completed in 5 weeks or less and thus 

could occur during the 5-week planned 

outage that each EGU typically has each 

year.235

Thus, for both EGUs and non-EGUs, 

EPA’s technical analysis for the 1998 

NOX SIP Call indicated that a 3-year 

period would be sufficient for 

installation of both combustion and 

post-combustion controls, from the 

planning and specification of controls to 

completion of control technology 

implementation.236 EPA’s evaluation of 

the timeframes for post-combustion 

controls was based on the Agency’s 

projection that 639 retrofit installations 

at EGU sources and 235 retrofit 

installations at non-EGU industrial 

sources would be necessary for existing 

sources in the covered states to comply 

with the NOX SIP Call.237 Although the 

scope of types of non-EGU sources 

covered by this proposed FIP is broader, 

and the estimated number of emissions 

units is greater (potentially including as 

many as 490 emissions units), than the 

scope and number of non-EGU sources 

evaluated in the 1998 NOX SIP Call, and 

although a later analysis of timeframes 

for installation of post-combustion 

controls at EGUs produced a more 

refined estimate for that sector only,238

EPA’s prior analyses nonetheless inform 

the evaluation in this proposal of the 

necessary implementation schedule for 

non-EGU sources given they generally 

address NOX control technologies 

similar to those that the EPA anticipates 

non-EGU sources may install to comply 

with the provisions of the proposed FIP 


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20104 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

239 69 FR 4566, 4617 (January 30, 2004) (citing 

Final Report, ‘‘Engineering and Economic Factors 

Affecting the Installation of Control Technologies 

for Multipollutant Strategies,’’ EPA–600/R–02/073 

(October 2002)). 

240Final Report, ‘‘Engineering and Economic 

Factors Affecting the Installation of Control 

Technologies for Multipollutant Strategies,’’ EPA– 

600/R–02/073 (October 2002), at 21. 

241Wisconsin, 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). 

242Wisconsin, 938 F.3d at 313–314, 319 (‘‘When 

an agency faces a statutory mandate, a decision to 

disregard it cannot be grounded in mere 

infeasibility’’). We note also that in the CSAPR 

Close-Out Rule (83 FR 65878, December 21, 2018), 

the EPA required no further reductions from 

upwind states beyond those set forth in the prior 

CSAPR Update based, in part, on the Agency’s 

conclusion that it was not feasible to implement 

cost-effective emissions controls before 2023, 2 

years after the 2021 attainment deadline for the 

downwind serious areas. The D.C. Circuit vacated 

the Close-Out Rule for its reliance on the same 

interpretation of the Good Neighbor Provision that 

the court had rejected in Wisconsin. New York v. 

EPA, 781 F. App’x 4 (D.C. Cir. 2019) (unpublished 

opinion). 

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

ultra-low NOX burners). 

Additionally, as part of EPA’s 

evaluation of installation timing needs 

in the proposed CAIR (69 FR 4566), the 

EPA projected that it would take on 

average 21 months to install an SCR on 

one EGU unit, 27 months to install a 

scrubber on one EGU unit, and 3 years 

to install seven SCRs at a single EGU.239

The EPA also noted that some EGUs 

could install SCR controls in as short of 

a period as 13 months.240 This 

information and EPA’s general 

experience indicate that a two-year 

installation timeframe for a rule 

requiring installation of new control 

technologies across a variety of 

emissions sources in several industries 

on a regional basis is a relatively fast 

installation timeframe, but that a 3-year 

installation timeframe should be 

feasible for most if not all of the 

identified industries. A shorter 

installation timeframe of approximately 

one year would likely raise significant 

challenges for sources, suppliers, 

contractors, and other economic actors, 

potentially including customers relying 

on the products or services supplied by 

the regulated sources. Thus, if the EPA 

finalizes this proposed rule in 2023, 

implementation of the necessary 

emissions controls across all of the 

affected non-EGU sources by the August 

3, 2024, Moderate area attainment date 

would not be possible. 

For purposes of this proposed rule, 

the EPA estimates that the required 

controls for non-EGU source categories 

would take up to 3 years to install 

across the affected industries in the 23 

states that remain linked in 2026. 

Therefore, based on the available 

information, the EPA proposes to 

require compliance with these non-EGU 

control requirements by the beginning 

of the 2026 ozone season. 

The EPA requests comment on the 

time needed to install the various 

control technologies across all of the 

emissions units in the Tier 1 and Tier 

2 industries. In particular, the EPA 

solicits comment on the time needed to 

obtain permits (including the potential 

applicability of NSR requirements), the 

availability of vendors and materials, 

design, construction, and the earliest 

possible installation times for SCR on 

glass furnaces; SNCR or SCR on cement 

kilns; ultra-low NOX burners, low NOX

burners, and SCR on ICI boilers (coalfired, gas-fired, or oil-fired); low NOX

burners on large non-EGU ICI boilers; 

and low emissions combustion, layered 

emissions combustion, NSCR, and SCR 

on reciprocating rich-burn or lean-burn 

IC engines. 

With respect to emissions monitoring 

requirements, EPA requests comment on 

the costs of installing and operating 

CEMS at non-EGU sources without NOX

emissions monitors; the time needed to 

program and install CEMS at non-EGU 

sources; whether monitoring techniques 

other than CEMS, such as predictive 

emissions monitoring systems (PEMS), 

may be sufficient for certain non-EGU 

facilities, and the types of non-EGU 

facilities for which such PEMS may be 

sufficient; and the costs of installing and 

operating monitoring techniques other 

than CEMS. 

The EPA also requests comment on 

whether the FIP should provide a 

limited amount of time beyond the 2026 

ozone season for individual non-EGU 

sources to meet the emissions 

limitations and associated compliance 

requirements, based on a facilityspecific demonstration of necessity. As 

the D.C. Circuit stated in Wisconsin, the 

good neighbor provision may be read to 

allow for some deviation from the 

mandate to eliminate prohibited 

transport by downwind attainment 

deadlines, ‘‘under particular 

circumstances and upon a sufficient 

showing of necessity,’’ provided such 

deviation is ‘‘rooted in Title I’s 

framework [and] provide[s] a sufficient 

level of protection to downwind 

States.’’ 241 Consistent with this 

directive, and recognizing that in 

general, the EPA aligns good neighbor 

obligations in the first instance with the 

last full ozone season before the 

downwind attainment date, the EPA 

requests comment on whether 

individual non-EGU sources should be 

allowed to request an extension of the 

May 1, 2026, compliance deadline by no 

more than 1 year (i.e., to May 1, 2027) 

based on a sufficient showing of 

necessity. Any such comments should 

be supported by a detailed discussion of 

the facility-specific economic, 

technological, and other circumstances 

that may justify such an extension. The 

EPA notes that claims about infeasibility 

of controls are generally insufficient to 

justify an extension of time to comply, 

given the Wisconsin court’s holding that 

the good neighbor provision requires 

upwind states to eliminate their 

significant contribution in accordance 

with the downwind states’ attainment 

deadlines, without regard to questions 

of feasibility.242

The EPA solicits comment on the 

specific criteria that the EPA should 

apply in evaluating requests for 

extension of the 2026 compliance 

deadline for non-EGU sources. Such 

criteria could include documentation of 

inability, despite best efforts, to procure 

necessary materials or equipment (e.g., 

equipment manufacturers are not able to 

deliver equipment before a specific 

date) or hire labor as needed to install 

the emissions control technology by 

2026; documentation of installation 

costs well in excess of the highest 

representative cost-per ton threshold 

identified for any source (including 

EGUs) discussed in Section VI of this 

proposed rule (e.g., vendor estimate 

showing equipment cost); 

documentation of a source owner or 

operator’s inability to secure necessary 

financing, due to circumstances beyond 

the owner/operator’s control, in time to 

complete the installation of controls by 

2026; or documentation of extreme 

financial or technological constraints 

that would require the subject non-EGU 

emissions unit or facility to significantly 

curtail its operations or shut down 

before it could comply with the 

requirements of this proposed rule by 

2026. Finally, the EPA requests 

comment on the process through which 

the EPA should review and act on an 

extension request—e.g., the appropriate 

deadline for submitting a request, and 

whether the EPA should provide an 

opportunity for public comment before 

granting or denying a request. 

The EPA anticipates that the owner or 

operator of the facility would bear the 

burden of establishing the necessity of 

an extension of time to comply, based 

on particular circumstances described 

and sufficiently documented in the 

submitted request. Claims of generalized 

financial or economic hardship or any 

claim that controls are not necessary to 

eliminate significant contribution would 


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243 If any of the states whose sources currently 

participate in the Group 3 trading program is 

determined in the final rule to not have additional 

emissions reduction requirements for EGUs, the 

EPA proposes in the alternative to establish a new 

trading program substantially similar to the revised 

Group 3 trading program described in this proposal 

that would cover units within the borders of all the 

states determined to have emissions reduction 

requirements for EGUs in the final rule. 

244Affected EGUs in the two other states 

currently covered by the Group 2 trading program— 

Iowa and Kansas—would continue to participate in 

that program. 

not suffice to justify an extension. If the 

EPA finalizes a provision allowing 

sources to request limited extensions of 

time to comply, the Agency would 

review each request on a case-by-case 

basis as necessary to ensure consistency 

with the provisions of title I of the CAA. 

B. Regulatory Requirements for EGUs 

To implement the required emissions 

reductions from EGUs, the EPA 

proposes to revise the existing CSAPR 

NOX Ozone Season Group 3 Trading 

Program (the ‘‘Group 3 trading 

program’’) established in the Revised 

CSAPR Update both to expand the 

program’s geographic scope and to 

enhance the program’s ability to ensure 

favorable environmental outcomes.243

The EPA proposes to use a trading 

program for EGUs because of the 

inherently greater flexibility that a 

trading program can provide relative to 

more prescriptive, ‘‘command-andcontrol’’ forms of regulation of sufficient 

stringency to achieve the necessary 

emissions reductions. In the electric 

power sector, EGUs’ extensive 

interconnectedness and coordination 

create the ability to shift both electricity 

production and emissions among units, 

providing a closely related ability to 

achieve emissions reductions in part by 

shifting electricity production from 

higher-emitting units to lower-emitting 

or non-emitting units. The sector’s 

unusual flexibility with respect to how 

emissions reductions can be achieved 

makes the flexibility of a trading 

program particularly useful as a means 

of lowering the overall costs of 

obtaining such reductions. In addition, 

it is essential for the electric power 

sector to retain short-term operational 

flexibility sufficient to allow electricity 

to be produced at all times in the 

quantities needed to meet demand 

simultaneously, and the flexibility of a 

trading program can be helpful in 

supporting this aspect of the industry as 

well. As discussed later, to provide 

improved environmental outcomes, in 

this rulemaking, the EPA is proposing 

certain enhancements to the current 

provisions of the Group 3 trading 

program addressing environmental 

performance that will necessarily 

reduce the flexibility of the individual 

units participating in the program to 

some extent. However, with the 

proposed enhancements, the EPA 

believes the inherently greater flexibility 

of a trading program continues to favor 

the use of this form of regulation, 

relative to more prescriptive forms of 

regulation, as a vehicle for achieving the 

emissions reductions from the electric 

power sector found to be necessary in 

this rulemaking. 

The Group 3 trading program 

currently applies to EGUs meeting the 

program’s applicability criteria within 

the borders of twelve states: Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, New Jersey, New 

York, Ohio, Pennsylvania, Virginia, and 

West Virginia. Affected EGUs in these 

twelve states would continue to 

participate in the Group 3 trading 

program as revised in this rulemaking, 

with some revised provisions taking 

effect in the 2023 control period and 

other revised provisions taking effect 

later as discussed elsewhere in this 

document. The EPA proposes to expand 

the Group 3 trading program’s 

geographic scope to include all of the 

additional states for which EGU 

emissions reduction requirements are 

being established in this rulemaking. 

Affected EGUs within the borders of 

eight states currently covered by the 

CSAPR NOX Ozone Season Group 2 

Trading Program (the ‘‘Group 2 trading 

program’’)—Alabama, Arkansas, 

Mississippi, Missouri, Oklahoma, 

Tennessee, Texas, and Wisconsin— 

would transition from the Group 2 

program to the revised Group 3 trading 

program at the beginning of the 2023 

control period,244 and affected EGUs 

within the borders of the five states not 

currently covered by any CSAPR trading 

program for seasonal NOX emissions— 

Delaware, Minnesota, Nevada, Utah, 

and Wyoming—would enter the Group 

3 trading program in the 2023 control 

period following the effective date of a 

final rule in this rulemaking. As is the 

case for the states already in the Group 

3 trading program, for each state added 

to the program, the set of affected EGUs 

would include new units as well as 

existing units and units located in 

Indian country within the state’s 

borders as well as units not located in 

Indian country. Sections VII.B.2 and 

VII.B.3 of this proposed rule provide 

additional discussion of the proposed 

geographic expansion of the Group 3 

trading program and the units in the 

expanded geography that would likely 

become subject to the program under 

the program’s existing applicability 

provisions. 

In addition to expanding the Group 3 

trading program’s geographic scope, the 

EPA proposes to modify the program’s 

regulations prospectively to include 

certain enhancements to improve 

environmental outcomes. Two of the 

proposed enhancements would adjust 

the overall quantities of allowances 

available for compliance in the trading 

program in each control period so as to 

maintain the rule’s selected control 

stringency and related EGU effective 

emissions rate performance level as the 

EGU fleet evolves. First, instead of 

establishing emissions budgets for all 

future years under the program at the 

time of the rulemaking, which cannot 

reflect future changes in the EGU fleet 

unknown at the time of the rulemaking, 

the EPA proposes to revise the trading 

program regulations to include a 

dynamic budgeting procedure. This 

procedure would calculate emissions 

budgets for control periods in 2025 and 

later years based on more current 

information about the composition and 

utilization of the EGU fleet, specifically 

data available from the 2023 ozone 

season and following (e.g., for 2025, 

data from 2023; for 2026, data from 

2024; etc.). (Associated revisions to the 

program’s variability limits and unitlevel allowance allocation procedures 

would coordinate these provisions with 

the revised budget-setting procedures.) 

Second, starting with the 2024 control 

period, the EPA proposes to annually 

recalibrate the quantity of accumulated 

banked allowances under the program 

to prevent the quantity of allowances 

carried over from each control period to 

the next from exceeding the target bank 

level, which would be revised to 

represent 10.5 percent of the sum of the 

state emissions budgets. Together, these 

enhancements would protect the 

intended stringency of the trading 

program against potential erosion 

caused by EGU fleet turnover and would 

better sustain over time the incentives 

created by the trading program to apply 

continuously the degree of emissions 

control the EPA determines is necessary 

to address states’ good neighbor 

obligations. 

Two further enhancements to the 

Group 3 trading program proposed in 

this rulemaking would establish 

provisions designed to promote more 

consistent emissions control by 

individual EGUs within the context of 

the trading program. First, starting with 

the 2024 control period for most coalfired EGUs with existing SCR controls 

and the 2027 control period for most 

other coal-fired EGUs, a daily NOX

emissions rate of 0.14 lb/mmBtu would 


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245The 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. 

246The 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. 

apply as a backstop to the more 

stringent seasonal emissions budgets. 

Each ton of emissions exceeding a unit’s 

backstop daily emissions rate would 

incur a 3-for-1 allowance surrender ratio 

instead of the usual 1-for-1 allowance 

surrender ratio. Second, also starting 

with the 2024 control period, the 

trading program’s existing assurance 

provisions, which require extra 

allowance surrenders from sources that 

are found responsible for contributing to 

an exceedance of the relevant state’s 

‘‘assurance level’’ (i.e., currently 121 

percent of the state’s emissions budget), 

would be strengthened by the addition 

of another backstop requirement. 

Specifically, for any unit found 

responsible for contributing to an 

exceedance of the state’s assurance 

level, the revised regulations would 

prohibit the unit’s seasonal emissions 

from exceeding by more than 50 tons 

the emissions that would have resulted 

if the unit had achieved a seasonal 

average emissions rate equal to the 

higher of 0.10 lb/mmBtu or 125 percent 

of the unit’s lowest previous seasonal 

average emissions rate under any 

CSAPR seasonal NOX trading 

program.245

These two enhancements are designed 

to ensure that all individual units with 

SCR controls have strong incentives to 

continuously operate and optimize their 

controls, and also to ensure that even 

units without SCR controls have strong 

incentives to optimize their emissions 

performance when a state’s assurance 

level might otherwise be exceeded. 

These enhancements are generally 

designed to ensure consistency with 

EPA’s determination regarding the 

emissions control stringency needed 

from EGUs to eliminate significant 

contribution under the Step 3 

multifactor analysis as discussed in 

Section VI of this proposed rule. 

Further, these enhancements are 

designed to provide greater assurance 

that emissions controls will be operated 

on all days of the ozone season and 

therefore necessarily on the days that 

turn out to be most critical for 

downwind ozone levels. The EPA 

expects that promoting more 

consistently good emissions 

performance by individual EGUs will 

also help address disparate impacts of 

pollution on overburdened communities 

from individual units that might 

otherwise have chosen not to optimize 

their emissions performance. 

1. Trading Program Background and 

Overview of Proposed Revisions 

a. Current CSAPR Trading Program 

Design Elements and Identified 

Concerns 

The use of allowance trading 

programs to achieve required emissions 

reductions from the electric power 

sector has a long history, rooted in the 

Clean Air Act Amendments of 1990. In 

Title IV of those amendments, Congress 

specified the design elements for a 48- 

state allowance trading program to 

reduce SO2 emissions and the resulting 

acid precipitation. Building on the 

success of that first allowance trading 

program as a tool for addressing multistate air pollution issues, since 1998 

EPA has promulgated and implemented 

multiple allowance trading programs for 

SO2 or NOX emissions to address the 

requirements of the CAA’s good 

neighbor provision with respect to 

successively more stringent NAAQS for 

fine particulate matter and ozone. Most 

of these trading programs have applied 

either exclusively or primarily to EGUs. 

The EPA currently administers six 

CSAPR trading programs for EGUs 

(promulgated in CSAPR, the CSAPR 

Update, and the Revised CSAPR 

Update) that differ in the pollutants, 

geographic regions, and time periods 

covered and in the levels of stringency, 

but that otherwise are nearly identical 

in their core design elements and their 

regulatory text.246 The principal 

common design elements currently 

reflected in all of the programs are as 

follows: 

• An ‘‘emissions budget’’ is 

established for each state for each 

control period, representing EPA’s 

quantification of the emissions that 

would remain under certain projected 

conditions after elimination of the 

emissions prohibited by the good 

neighbor provision under those 

projected conditions. For each control 

period of program operation, a quantity 

of newly issued ‘‘allowances’’ equal to 

the amount of each state’s emissions 

budget is allocated among the state’s 

sources. (States have options to replace 

EPA’s default allocations or to institute 

an auction process.) Total emissions in 

a given control period from all sources 

in the program are effectively capped at 

a level no higher than the total quantity 

of allowances available for use in the 

control period, consisting of the sum of 

all states’ emissions budgets for the 

control period plus any unused 

allowances carried over from previous 

control periods as ‘‘banked’’ allowances. 

• ‘‘Assurance provisions’’ in each 

program establish an ‘‘assurance level’’ 

for each state for each control period, 

defined as the sum of the state’s 

emissions budget plus a specified 

‘‘variability limit.’’ The purpose of the 

assurance provisions is to limit the total 

emissions from each state’s sources in 

each control period to an amount close 

to the state’s emissions budget for the 

control period, consistent with the good 

neighbor provision’s mandate that 

required emissions reductions must be 

achieved within the state, while 

allowing some flexibility beyond the 

emissions budget to accommodate yearto-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 nonsource entities—and also let allowances 

that are unused in one control period be 

carried over for use in future control 

periods as banked allowances. Although 

the programs do not directly limit either 

trading or banking of allowances, the 3- 

for-1 surrender ratio imposed by the 


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247With the exception of the proposed 

conforming revisions to allowance recordation 

schedules discussed in Section VII.B.12 of this 

proposed rule, the EPA is not proposing in this 

rulemaking to extend the enhancements proposed 

for the Group 3 trading program to the other CSAPR 

trading programs. 

assurance provisions on any emissions 

exceeding a state’s assurance level 

disincentivizes sources from relying on 

either in-state banked allowances or net 

out-of-state purchased allowances to 

emit over the assurance level. 

• Finally, other common design 

elements ensure program integrity, 

source accountability, and 

administrative transparency. Most 

notably, each unit must monitor and 

report emissions and operational data in 

accordance with the provisions of 40 

CFR part 75; all allowance allocations or 

auction results, transfers, and 

deductions must be properly recorded 

in EPA’s Allowance Management 

System; each source must have a 

designated representative who is 

authorized to represent all of the 

source’s owners and operators and is 

responsible for certifying the accuracy 

of the source’s reports to the EPA and 

overseeing the source’s Allowance 

Management System account; and 

comprehensive data on emissions and 

allowances are made publicly available. 

The EPA continues to believe that the 

current CSAPR trading program 

structure established by the common 

design elements described previously 

has important positive attributes, 

particularly with respect to the 

exceptional degree of compliance 

flexibility it can provide to a sector such 

as the electric power sector where such 

flexibility is especially useful and 

valuable. However, the EPA also shares 

some stakeholders’ concerns about 

whether the current structure, without 

enhancements, is capable of adequately 

addressing states’ good neighbor 

obligations with respect to the 2015 

ozone NAAQS in light of the rapidly 

evolving EGU fleet and the stringency 

and short-term form of the standard. 

One set of concerns relates to the 

observed tendency under the current 

trading programs for the supply of 

allowances to grow over time while the 

demand for allowances falls, reducing 

allowance prices and eroding the 

consequent incentives for sources to 

effectively control their emissions. A 

second, overlapping set of concerns 

relates to the general absence of sourceor unit-specific emissions reduction 

requirements, allowing some individual 

sources to idle existing emissions 

controls. Emissions from these 

individual sources can contribute to 

increased pollution concentrations 

downwind on the particular days that 

matter for downwind exceedances of the 

relevant air quality standard and also 

have the potential to cause 

disproportionate adverse impacts on 

downwind overburdened communities. 

The EPA has analyzed hourly emissions 

data reported in prior cap-and-trade 

programs and identified instances of 

sources that did not operate SCR 

controls for substantial portions of 

recent ozone seasons. In an effort to 

maintain as much compliance and 

operational flexibility as possible, 

ensure controls happen on critically 

important highest ozone days, guard 

against this behavior under a more 

stringent NAAQS, and provide relief to 

overburdened communities, the EPA 

would require control operation every 

day through a unit-level emission rate 

designed to ensure reductions occur on 

the highest ozone days in addition to 

maintaining a mass-based seasonal 

requirement. To meet the statutory 

requirement to eliminate significant 

contribution and interference with 

maintenance on the critically important 

days, this combination of requirements 

would require sources to plan to run 

controls all season, including the 

highest ozone days, while giving 

reasonable flexibility for occasional 

operational needs. 

In this rulemaking, the EPA is 

proposing to revise the Group 3 trading 

program to include enhancements 

designed to address both sets of 

concerns described above.247 The 

principles guiding the various proposed 

revisions and the relationships of the 

revisions to one another are discussed 

in Sections VII.B.1.b and VII.B.1.c of 

this proposed rule. The individual 

proposed revisions are discussed in 

more detail in Sections VII.B.4 through 

VII.B.9 of this proposed rule. 

b. Enhancements To Maintain Selected 

Control Stringency Over Time 

The first set of concerns noted about 

the current CSAPR trading program 

structure relates to the programs’ ability 

to maintain the rule’s selected control 

stringency and related EGU effective 

emissions rate performance level as the 

EGU fleet evolves over time. Under the 

structure of the current CSAPR trading 

programs, the effectiveness of the 

programs at maintaining the rule’s 

selected control stringency depends 

entirely on how allowance prices over 

time compare to the costs of sources’ 

various emissions reduction 

opportunities, which in turn depends 

on the relationship between the supply 

for allowances and the demand for 

allowances. In considering possible 

ways to address concerns about the 

ability to enhance the current trading 

program structure to better sustain 

incentives to control emissions over 

time, the EPA has focused on the 

trading program design elements that 

determine the supply of allowances, 

specifically the approach for setting 

state emissions budgets and the rules 

concerning the carryover of unused 

allowances for use in future control 

periods as banked allowances. 

i. Revised Emissions Budget-Setting 

Process 

In each of the previous rulemakings 

establishing CSAPR trading programs, 

the EPA has evaluated the emissions 

that could be eliminated through 

implementation of certain types of 

emissions control strategies available at 

various cost thresholds to achieve 

certain rates of emissions per unit of 

heat input (i.e., the amount of fuel 

consumed) and the effects of the 

resulting emissions reductions on 

downwind air quality. After 

determining the emissions control 

strategies and associated emissions 

reductions that should be required 

under the good neighbor provision by 

considering these factors in a 

multifactor test, the EPA has then 

projected the amounts of emissions that 

would remain after the assumed 

implementation of the selected 

emissions control strategies at various 

points in the future and has established 

the projected remaining amounts of 

emissions as the state emissions budgets 

in trading programs. 

Projecting the amounts of emissions 

remaining after implementation of 

selected emissions controls necessarily 

requires projections not only for 

sources’ future emissions rates but also 

for other factors that influence total 

emissions, notably the composition of 

the future EGU fleet (i.e., the capacity 

amounts of different types of sources 

with different emissions rates) and their 

future utilization levels (i.e., their heat 

input). To the extent the projections 

made at the time of a rulemaking for 

these other factors prove inaccurate, 

over time the emissions budgets may 

not reflect the intended stringency of 

the emissions control strategies 

identified in the rulemaking as 

consistent with addressing states’ good 

neighbor obligations. Further, projecting 

EGU fleet composition and utilization 

has become increasingly challenging in 

light of the rapid evolution of the 

electric power sector toward more 

efficient and cleaner sources of 

generation, driven by factors including 

lower prices for natural gas and wind 

and solar generation. 


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248The price of allowances in CSAPR Update 

states started out at levels near $800 per ton in 2017 

but declined to less than $100 per ton by 2019 and 

were less than $70 per ton in July 2020 (data from 

S&P Global Market Intelligence). 

249 86 FR 23117. 

250See EPA–HQ–OAR–2020–0272–0094. ‘‘. . . is 

demonstrated through examination of Maryland’s 

ozone design value days for June 26th–28th, 2019. 

On those days, Maryland recorded 8-hour ozone 

levels of 75, 85 and 83 ppb at the Edgewood 

monitor. Maryland Department of the Environment 

evaluated the daily NOX emission rate for units in 

Pennsylvania that were found to influence the 

design values on the 3 exceedance days (and 1 day 

prior to the exceedance) against the past-best ozone 

season 30-day rolling average optimized NOX rate 

(which tends to be higher than the absolute lowest 

seasonal average rate).’’ 

251Emission reductions derived from generation 

shifting will be captured in the dynamic budgets in 

all cases. For the pre-set budget years it is estimated 

and incorporated through an additional calculation 

step. For dynamic budget years, it is directly 

incorporated through the inclusion of updated heat 

input data reflecting observed, compliance period 

generation shifting. 

A consequence of using a trading 

program approach with preset emissions 

budgets that do not keep pace with the 

trends in EGU fleet composition and 

heat input is that the preset emissions 

budgets maintain the supply of 

allowances at levels that increasingly 

exceed the emissions that would occur 

even without implementation of the 

emissions control strategies used as the 

basis for determining the emissions 

budgets, causing decreases in allowance 

prices and hence the incentives to 

implement the control strategies. As an 

example, although the emissions 

budgets in the CSAPR Update 

established in 2016 reflected 

implementation of the emissions control 

strategy of operating and optimizing 

existing SCR controls, within 4 years the 

EPA found that EGU retirements and 

changes in utilization not anticipated in 

EPA’s previous budget-setting 

computations had made it economically 

attractive for at least some sources to 

idle or reduce the effectiveness of their 

existing controls (relying on purchased 

allowances instead).248 While the EPA 

has provided analysis indicating that, 

on average, sources operate their 

controls more effectively on high 

electric demand days, it has also 

identified cases where units fail to 

optimize their controls on these days. 

Downwind states have suggested this 

type of reduced pollution control 

performance has occurred on the day 

and preceding day of an ozone 

exceedance.249 250 Such an outcome 

undermined the ongoing achievement of 

emissions rate performance consistent 

with the control strategies defined to 

eliminate significant contribution to 

nonattainment and interference with 

maintenance, including continuous 

operation and optimization of existing 

controls. 

In the Revised CSAPR Update, the 

EPA took steps to better address the 

rapid evolution of the EGU fleet, 

specifically by setting updated 

emissions budgets for individual future 

years though 2024 that reflect future 

EGU fleet changes known with 

reasonable certainty at the time of the 

rulemaking. Some commenters 

requested that the EPA also update the 

year-by-year emissions budgets to reflect 

future fleet changes that might become 

known after the time of the rulemaking, 

but the EPA declined to do so, in part 

because no methodology for making 

future emissions budget adjustments in 

response to post-rulemaking data had 

been included in the proposal for the 

rulemaking. 

Based on information available as of 

December 2021, it appears that the 

emissions budgets set for the first 

control period covered by the Revised 

CSAPR Update generally succeeded at 

creating incentives to operate emissions 

controls under the Group 3 trading 

program for the programs’ first control 

period. However, the EPA recognizes 

that the lack of emissions budget 

adjustments after 2024 in conjunction 

with industry trends toward more 

efficient and cleaner resources would 

likely lead to a surplus of allowances 

after the adjustments end. In this 

rulemaking, besides setting new 

emissions budgets for the 2023 and 2024 

control periods, the EPA also proposes 

to extend the Group 3 trading program 

budget-setting methodology used in the 

Revised CSAPR Update to routinely set 

emissions budgets for each future 

control period in the year before that 

control period, with each emissions 

budget reflecting the latest available 

information on the composition and 

utilization of the EGU fleet at the time 

that emissions budget is determined. 

The current budget-setting 

methodology established in the Revised 

CSAPR Update and the proposed 

revisions are discussed in detail in 

Section VII.B.4 of this proposed rule 

and the Ozone Transport Policy 

Analysis Proposed Rule TSD. To 

summarize here, the Revised CSAPR 

Update’s emissions budget-setting 

methodology includes three primary 

steps: (1) Establishment of a baseline 

inventory of EGUs adjusted for known 

retirements and new units, with heat 

input and emissions rate data for each 

EGU in the inventory based on recent 

historical data; (2) adjustment of the 

baseline data to reflect assumed 

emissions rate changes resulting from 

known new controls, known gas 

conversions, and implementation of the 

emissions control strategies used to 

determine states’ good neighbor 

obligations; and (3) application of an 

increment or decrement to reflect the 

effect on emissions from projected 

generation shifting among the units in a 

state at the emissions reduction cost 

associated with the selected emissions 

control strategies. In this rulemaking, 

the EPA proposes to modify this 

methodology in two ways. First, the 

baseline EGU inventory and heat input 

data, but not the emissions rate data, 

would be updated for each control 

period using the most recent available 

reported data. For example, in early 

2024, using the final data reported for 

2023, the EPA would update the 

baseline inventory and heat input data 

used to determine state emissions 

budgets for the 2025 control period. 

Second, the EPA would not apply an 

increment or decrement to any state 

emissions budget for projected 

generation shifting associated with 

implementation of the selected control 

strategies, because any such shifting 

should already be reflected in the heat 

input data used to update the 

baseline.251

The EPA believes that the proposed 

revisions to the emissions budget-setting 

process would substantially improve the 

ability of the emissions budgets to keep 

pace with changes in the composition 

and utilization of the EGU fleet. The 

revised methodology would account for 

the electric power sector’s overall trends 

toward more efficient and cleaner 

resources, both of which tend to 

decrease total heat input at affected 

EGUs. The revised methodology would 

also account for other factors that could 

lead to increased heat input in some 

states, such as generation shifting from 

other states or increases in electricity 

demand caused by rising electrification. 

The updating procedure would be 

specified in the program regulations and 

the computations, which would be 

straightforward, could be performed in 

a spreadsheet to deliver reliable results. 

EPA would provide public notice of the 

preliminary calculations and the data 

used by March 1 of the year preceding 

the control period and would provide 

an opportunity for submission of any 

objections to the data and preliminary 

calculations before finalizing the 

budgets for each control period by May 

1 of the year before the control period 

to which those budgets apply. Thus, for 

example, sources and other stakeholders 

will have certainty by May 1, 2024, of 

the emissions budgets that will be set 

for the 2025 control period that starts 

May 1, 2025. 


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252The advantages of trading programs discussed 

earlier in this section—providing continuous 

emissions reduction incentives, facilitating 

compliance cost minimization, and supporting 

operational flexibility—depend on the existence of 

a marketplace for purchasing and selling 

allowances, and broader marketplaces generally 

provide greater market liquidity and therefore make 

trading programs better at providing these 

advantages. The EPA recognizes that unrestricted 

use of net purchased allowances—meaning 

quantities of purchased allowances that exceed the 

quantities of allowances sold—by a source or group 

of sources as an alternative to making emissions 

reductions can interfere with the achievement of 

the desired environmental outcome, and Section 

VII.B.1.c of this proposed rule discusses the 

enhancements to the Group 3 trading program that 

the EPA is proposing in this rulemaking to reduce 

reliance on net purchased allowances by 

incentivizing or requiring better environmental 

performance at individual EGUs. However, the 

concern arises from the use of an excessive quantity 

of net purchased allowances for a particular 

purpose, not from the existence of a marketplace 

where allowances may be freely bought and sold. 

253The EPA recognizes there will be a data lag 

inherent in the future year emissions budgets, 

because the budgets would reflect fleet composition 

and utilization data reported for a previous control 

period. This means that the budgets for some 

individual control periods may fail to fully keep 

pace with the EGU fleet’s trends toward more 

efficient and cleaner resources. Nonetheless, the 

new approach is a substantial improvement in 

environmental performance of the program 

compared to a more unlimited approach to 

allowance banking. 

It bears emphasis that the annually 

updated information would concern 

only the composition and utilization of 

the EGU fleet and not the emissions rate 

data also used in the emissions budget 

computations. The emissions budget 

computations for all years would reflect 

only the specific emissions control 

strategies used to determine states’ good 

neighbor obligations as determined in 

this rulemaking, along with fixed 

historical emissions rates for units that 

are not assumed to implement 

additional control strategies, thereby 

ensuring that the annual updates would 

eliminate emissions as determined to be 

required under the good neighbor 

provision. The stringency of the 

emissions budgets would simply reflect 

the stringency of the emissions control 

strategies determined in the Step 3 

multifactor analysis and would do so 

more consistently over time than EPA’s 

previous approach of computing 

emissions budgets for all future control 

periods at the time of the rulemaking. 

The proposed revisions to state 

emissions budgets and the budgetsetting process are discussed further in 

Section VII.B.4 of this proposed rule. 

Proposed coordinated revisions to the 

determination of state-level variability 

limits and assurance levels and to unitlevel allowance allocations are 

discussed in Sections VII.B.5 and 

VII.B.9 of this proposed rule, 

respectively. 

ii. Allowance Bank Recalibration 

Besides the levels of the emissions 

budgets, the second design element of 

the trading program structure that 

affects the supply of allowances in each 

control period, and that consequently 

also affects the ability of a trading 

program to maintain the rule’s selected 

control stringency and related EGU 

effective emissions rate performance 

level as the EGU fleet evolves over time, 

is the set of rules concerning the 

carryover of unused allowances for use 

in future control periods as banked 

allowances. As noted previously, 

trading and banking of allowances in 

the CSAPR trading programs can serve 

a variety of purposes: Continuously 

incentivizing sources to reduce their 

emissions even when they already hold 

sufficient allowances to cover their 

expected emissions for a control period, 

facilitating compliance cost 

minimization, accommodating 

necessary operational flexibility, and 

promoting allowance market liquidity. 

All of these purposes are advanced by 

rules that allow sources to trade 

allowances freely (both with other 

sources and with non-source entities 

such as brokers). All of these purposes 

are also advanced by rules that allow 

unused allowances to be carried over for 

possible use in future control periods, 

thereby preserving a value for the 

unused allowances. However, while the 

EPA considers it generally advantageous 

to place as few restrictions on the 

trading of allowances as possible,252

unrestricted banking of allowances has 

a potentially significant disadvantage 

offsetting its advantages, namely that it 

allows what might otherwise be 

temporary surpluses of allowances in 

some individual control periods to 

accumulate into a long-term allowance 

surplus that reduces allowances prices 

and weakens the trading program’s 

incentives to control emissions. With 

weakened incentives, some operators 

would be more likely to choose not to 

continuously operate and optimize their 

emissions controls, imperiling the 

ongoing achievement of emissions rate 

performance consistent with the control 

strategies defined as eliminating 

significant contribution to 

nonattainment and interference with 

maintenance. 

As discussed in detail in Section 

VII.B.6 of this proposed rule, the EPA is 

proposing to revise the Group 3 trading 

program by adding provisions that 

would establish a routine recalibration 

process for banked allowances that 

would be carried out in August 2024 

and each subsequent August, after the 

compliance deadline for the control 

period in the previous year. In each 

recalibration, the EPA would reset the 

total quantity of banked allowances for 

the Group 3 trading program (‘‘Group 3 

allowances’’) held in all Allowance 

Management System accounts to a target 

level of 10.5 percent of the sum of the 

state emissions budgets for the current 

control period. The procedure would 

entail identifying the ratio of the target 

bank amount to the total quantity of 

banked allowances held in all accounts 

before the conversion and then, if the 

ratio was less than 1.0, multiplying the 

quantity of banked allowances held in 

each account by the ratio to identify the 

appropriate recalibrated amount for the 

account (rounded to the nearest 

allowance), and deducting any 

allowances in the account exceeding the 

recalibrated amount. 

The EPA believes this revision to the 

Group 3 trading program’s banking 

provisions would complement the 

proposed revisions to the budget-setting 

process by ensuring that the annual 

bank recalibration would prevent any 

surplus of allowances created in one 

control period from diminishing the 

intended stringency and resulting 

emissions reductions of the emissions 

budgets for subsequent control 

periods.253

The calibration procedure would not 

erase the value of unused allowances for 

the holder, because the larger the 

quantity of banked allowances that is 

held in a given account before each 

recalibration, the larger the quantity of 

banked allowances that would be left in 

the account after the recalibration for 

possible sale or use in meeting future 

compliance requirements. Because the 

banked allowances would always have 

value, the opportunity to bank 

allowances would continue to advance 

the purposes served by otherwise 

unrestricted banking as described above. 

Opportunities to bank unused 

allowances can serve all these same 

purposes whether a banked allowance is 

of partial value (if the bank needs 

recalibrating to its target level) or is of 

full value compared to a newly issued 

allowance for the next control period. 

The proposal to routinely recalibrate 

the allowance bank is discussed further 

in Section VII.B.6 of this proposed rule. 

d. Enhancements To Improve Emissions 

Performance at Individual Units 

The second set of concerns about the 

structure of the current CSAPR trading 

programs relates to the general absence 

of source- or unit-specific emissions 

reduction requirements. Without such 

requirements, the programs affect 

individual sources’ emissions 


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254EPA–HQ–OAR–2020–0272. Comment 

submitted by Ben Grumbles, Secretary, Maryland 

Department of the Environment (MDE). 

255The CSAPR Update was a partial remedy and 

the Revised CSAPR Update addressed downwind 

nonattainment and maintenance issues that were 

projected to be resolved within a 4 year window. 

In contrast, this rule reflects a full remedy and is 

addressing downwind nonattainment and 

maintenance issues that are projected to persist for 

more than a decade. 

performance only to the extent that the 

incentives created by allowance prices 

are high enough relative to the costs of 

the sources’ various emissions control 

opportunities. In circumstances where 

the incentives to control emissions are 

insufficient, some individual sources 

even idle existing emissions controls. 

Emissions from these individual sources 

can contribute to increased pollution 

concentrations downwind on the 

particular days that matter for 

downwind exceedances of the relevant 

air quality standard and also have the 

potential to cause disproportionate 

adverse impacts on downwind 

overburdened communities. 

This EPA intends that the trading 

program enhancements described in 

Section VII.B.1.b of this proposed rule 

would improve the Group 3 trading 

program’s ability to sustain emissions 

control incentives over time such that 

needed emissions performance would 

be achieved by all participating units 

without the need for additional 

requirements to be imposed at the level 

of individual units. However, because 

obtaining needed emissions 

performance at individual units is also 

important, the EPA proposes to 

supplement the previously discussed 

enhancements with two other new sets 

of provisions that would apply to 

certain individual units within the 

larger context of the Group 3 trading 

program. The allowance price would 

continue to be the most important driver 

of good environmental performance for 

most units, but the proposed unit-level 

requirements would be important 

supplemental drivers of performance 

and would offer additional assurance 

that significant contribution is 

eliminated on a daily basis during the 

ozone season by continuous operation 

of existing pollution controls. 

i. Unit-Specific Backstop Daily 

Emissions Rates 

The first of the proposed trading 

program enhancements intended to 

improve emissions performance at the 

level of individual units is the addition 

of backstop daily NOX emissions rate 

provisions that would apply to large 

coal-fired EGUs, defined for this 

purpose as units serving electricity 

generators with nameplate capacities 

equal to or greater than 100 MW and 

combusting any coal during the control 

period in question. Starting with the 

2024 control period, a 3-for-1 allowance 

surrender ratio (instead of the usual 1- 

for-1 surrender ratio) would apply to 

emissions during the ozone season from 

any large coal-fired EGU with existing 

SCR controls exceeding a daily average 

NOX emissions rate of 0.14 lb/mmBtu. 

The additional allowance surrender 

requirement would be integrated into 

the trading program as a new 

component in the calculation of each 

unit’s primary emissions limitation, 

such that the additional allowances 

would have to be surrendered by the 

same compliance deadline of June 1 

after each control period. The amount of 

additional allowances to be surrendered 

would be determined by computing, for 

each day of the control period, any 

excess of the unit’s reported emissions 

(in pounds) over the emissions that 

would have resulted from combusting 

that day’s actual heat input at an 

average daily emissions rate of 0.14 lb/ 

mmBtu, summing the daily amounts, 

converting from pounds to tons, and 

multiplying by two. Starting with the 

2027 control period, the 3-for-1 

surrender ratio would apply in the same 

way to all large coal-fired EGUs, 

consistent with EPA’s proposed 

determinations, first, that a control 

stringency reflecting installation and 

operation of SCR controls on all large 

coal-fired EGUs is appropriate to 

address states’ good neighbor 

obligations with respect to the 2015 

ozone NAAQS, and second, that such 

controls could reasonably be installed 

by the 2026 control period. 

In prior rules addressing interstate 

transport of air pollution, stakeholders 

have noted that while seasonal cap-andtrade programs are effective at lowering 

ozone and ozone-forming precursors 

across the ozone season, attainment of 

the standard is measured on key days 

and therefore it is necessary to ensure 

that the rule requires emissions 

reductions not just seasonally, but also 

on those key days.254 They have noted 

that while the trading programs 

established under the NOX SIP Call, 

CAIR, and CSAPR have all been 

successful in ensuring seasonal 

reductions, states must remain below 

daily peak levels, not just seasonal 

levels, to reach attainment. These 

downwind stakeholder communities 

have suggested that operating pollution 

controls on the highest ozone days (and 

immediately preceding days) during the 

ozone season is of critical importance. 

The EPA has analyzed hourly emissions 

data reported in prior cap-and-trade 

programs and has identified instances of 

sources that did not operate SCR 

controls for substantial portions of 

recent ozone seasons. These instances 

are discussed below and in the EGU 

NOX Mitigation Strategies Proposed 

Rule TSD in the docket. While the EPA 

has in prior ozone transport actions not 

found sufficient evidence of emissions 

control idling or non-operation to take 

the step of building in enhancements to 

the trading program to ensure unit-level 

control operation, our review of that 

information applied to this context 

suggests this problem could become 

more prevalent in future years relevant 

to this action. Rather than allow for the 

potential of continued deterioration in 

the environmental performance of our 

trading programs, the EPA finds the 

evidence of declining SCR performance 

in later years of trading programs 

sufficient to justify prophylactic 

measures in this proposal to ensure the 

emissions control strategy selected at 

Step 3 is indeed implemented at Step 4. 

Thus, particularly in the context of the 

more stringent 2015 ozone NAAQS 

combined with the full remedy nature of 

this action and the extended timeframe 

for which upwind contribution to 

downwind nonattainment is projected 

to persist, the EPA agrees with these 

stakeholders that the set of measures 

promulgated in this rulemaking to 

implement the control stringency levels 

found necessary to address states’ good 

neighbor obligations should include 

measures designed to more effectively 

ensure that individual units operate 

their emission controls routinely 

throughout the ozone season, thereby 

also ensuring that the controls are 

planned to be in operation on the 

particular days that turn out to be most 

critical for ozone formation and for 

attainment of the NAAQS.255 Routine 

operation of emissions controls will also 

provide relief to overburdened 

communities downwind of any units 

that might otherwise have chosen not to 

operate their controls. In the Ozone 

Transport TSD, the EPA conducted a 

screening analysis that found nearly all 

of the EGUs included in this analysis 

are located within a 24-hour transport 

distance of many areas with potential EJ 

concerns. The EPA is proposing to 

adopt backstop daily rate limits at the 

individual unit level for this purpose, 

implemented in the context of a trading 

program (i.e., through enhanced 

allowance surrender ratios), as an 

alternative to adopting enforceable rate 

limits. 

The purpose of establishing a 

backstop daily NOX emissions rate and 

implementing it through additional 


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256EPA–HQ–OAR–2020–0272–0094. 

257While the proposed design of the daily 

emissions rate provision would not deter another 

theoretical type of poor emissions control 

behavior—i.e., turning off emissions controls at 

times of peak electricity demand in order to sell the 

additional electricity that otherwise would have 

been used to run the control equipment—EPA’s 

analysis of hourly emissions data does not show 

that this behavior is actually occurring. The data 

actually suggest the opposite—that emissions 

controls are generally operated better on peak 

demand days than on other days. See the Ozone 

Policy Analysis Proposed Rule TSD for additional 

details about the assessment of the tons and the 

Discussion of Short-term Emissions Limit document 

for an assessment of control operation on peak 

demand days. 

allowance surrender requirements 

instead of as an enforceable rate limit is 

to incentivize improved emissions 

performance at the individual unit level 

while continuing to preserve, to the 

extent possible, the advantages that the 

flexibility of a trading program brings to 

the electric power sector. As discussed 

in Section VII.B.7 of this proposed rule, 

under existing trading programs without 

the enhancements proposed in this 

rulemaking, some individual coal-fired 

units with SCR controls have chosen to 

operate the controls at lower removal 

efficiencies than in past ozone seasons 

or even to idle the controls for entire 

ozone seasons. In addition, some SCRequipped units have chosen to routinely 

cycle their emissions controls off at 

lower load levels, such as while 

operating overnight, instead of operating 

the controls, upgrading the units to 

enable the controls to be operated under 

those conditions, or not operating the 

units under those conditions. 

The EPA has identified sources of 

interstate ozone pollution such as the 

New Madrid and Conemaugh plants (in 

Missouri and Pennsylvania, 

respectively) whose SCR controls were 

not operating for substantial portions of 

recent ozone seasons. The data in 

Figures 1 and 2 to Section VII.B.1.c.i, 

included in Appendix G of the Ozone 

Transport Policy Analysis Proposed 

Rule TSD available in the docket for this 

rulemaking, demonstrate that these 

units have operated their SCRs better 

and more consistently during years with 

higher NOX allowance prices. 

Downwind stakeholders have noted that 

some of the higher emission rates 

(specifically in the case of Conemaugh 

Unit 2 in 2019) have occurred on the 

day of and the preceding day of an 

ozone exceedance in bordering states.256

The EPA believes that the design of 

the proposed daily emissions rate 

provisions would be effective in 

addressing these types of high-emitting 

behavior by significantly raising the cost 

of planned operator decisions that 

substantially compromise 

environmental performance. At the 

same time, the provision would not 

unduly penalize an occasional 

unplanned exceedance, because the 

amount of additional allowances that 

would have to be surrendered to address 

a single day’s exceedance would be 

much smaller than the amount that 

would have to be surrendered to address 

planned poor performance sustained 

over longer time periods.257

The EPA proposes to apply the daily 

emissions rate provisions to large coalfired 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 wellestablished as best practice for control 

of NOX emissions from coal-fired EGUs, 

as evidenced by the fact that the 

technology is already installed on more 

than 60 percent of the sector’s total coalfired capacity. In the context of the need 

for states to address their good neighbor 

obligations with respect to the 2015 

ozone NAAQS, the EPA is proposing to 

determine that a control stringency 

reflecting universal installation and 

operation of SCR technology at large 

coal-fired EGUs is appropriate, based on 

a multi-factor test that includes 

consideration of cost-effectiveness along 

with air quality factors. Finally, where 

SCR controls are installed, optimized 

operation of those controls is an 

extremely cost-effective method of 

achieving NOX emissions reductions. 

The EPA believes these considerations 

support establishment of the proposed 

daily emissions rate provisions on a 

universal basis for large coal-fired EGUs, 

with near-term application of the 

provisions for units that already have 

the controls installed and deferred 

application for other units, as discussed 

later. 

With regard to gas-fired steam EGUs, 

SCR controls are nowhere near as 

prevalent, and while the EPA is 

proposing to include some SCR controls 

at gas-fired steam units in the selected 

control stringency, the EPA is not 

proposing to include universal SCR 

controls at gas-fired steam units. 

Because the EPA does not propose to 

determine that universal installation 

and operation of SCR controls at gasfired steam EGUs is part of the selected 

control stringency, in order not to 

constrain the power sector’s flexibility 

to choose which particular gas-fired 

steam EGUs are the preferred candidates 

for achieving the required emissions 

reductions, the EPA is not proposing to 

apply the daily emissions rate 

provisions to large gas-fired steam 

EGUs. Focusing the backstop daily 

emissions rates on coal-fired units is 

also consistent with stakeholder input 

which has emphasized the need for 

short-term rate limits at coal units given 

their relatively higher emissions rates. 

The EPA developed the proposed 

level of the daily average NOX emissions 

rate—0.14 lb/mmBtu—through analysis 

of historical data, as described in 

Section VII.B.7 of this proposed rule. A 

rate of 0.14 lb/mmBtu represents the 

daily average NOX emissions rate that 

has been demonstrated to be achievable 

on approximately 95 percent of days 

covering more than 99 percent of total 

ozone-season NOX emissions by coalfired units with SCR controls that are 

achieving a seasonal NOX average 

emissions rate of 0.08 lb/mmBtu (or 

less), which is the seasonal NOX

emissions rate that the EPA has 

determined is indicative of optimized 

SCR performance by units with existing 

SCR controls. 

As noted previously, the daily average 

emissions rate provisions are proposed 

to apply beginning in the 2024 control 

period for large coal-fired units with 

installed SCR controls, one control 

period later than optimization of those 

controls would be reflected in the state 

emissions budgets under the proposal. 

Likewise, the daily average emissions 

rate provisions are proposed to apply 

beginning in the 2027 control period for 

other large coal-fired units, one control 

period later than emissions reductions 

consistent with the installation and 

operation of SCR controls for such units 

would be reflected in the state 

emissions budgets under the proposal. 

With respect to the units with existing 

SCR controls, not applying the daily 

average rate provisions until 2024 

would serve two purposes. First, it 

would provide all the units with a 

preparatory interval to focus attention 

on improving not only the average 

performance of their SCR controls but 

also the day-to-day consistency of 

performance before they would be held 

to increased allowance-surrender 

consequences for exceeding the daily 

rate. Second, it would provide the 

subset of units that exhaust to common 

stacks with other units that currently 

lack SCR controls an opportunity to 

exercise the option to install and certify 

any additional monitoring systems 

needed to monitor the individual units’ 

NOX emissions rates separately; 

otherwise, the daily emissions rate 

provisions would apply to the SCRequipped units based on the combined 


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258Based on the information reported by sources 

to the EPA in their monitoring plans under 40 CFR 

part 75, five plants subject to this proposal have 

SCR-equipped and non-SCR-equipped coal-fired 

EGUs that exhaust together to common stacks: The 

Clifty Creek plant in Indiana; the Cooper, Ghent, 

and Shawnee plants in Kentucky; and the Sammis 

plant in Ohio. 

NOX emissions rates measured in the 

common stacks.258

With respect to the units without 

existing SCR controls, not applying the 

daily average emissions rate provisions 

until 2027 would also serve two 

purposes. First, it would provide a 

window for plant personnel to gain 

experience operating any new SCR 

controls, and second, it would provide 

some timing flexibility for any 

individual unit operators who fail to 

complete SCR control installations 

before the start of the 2026 control 

period. With respect to both sets of 

units, the EPA believes that the lag in 

applicability of one control period is 

permissible because the emissions 

budget provisions are the principal 

provisions intended to drive the 

emissions reductions required under the 

proposal, while the daily average 

emissions rate provisions are included 

only to backstop those provisions. 

The EPA believes that the proposed 

unit-specific daily emissions rate 

provisions would strengthen the 

incentives for individual coal-fired units 

with SCR controls to operate and 

optimize performance of the controls. 

Continuous operation and optimization 

of post-combustion controls at 

individual units would help address 

individual days that prove in real time 

to be most critical for downwind ozone 

levels. Better continuous emissions 

performance by individual units would 

also help address disparate impacts of 

pollution on overburdened communities 

downwind from the units. 

The proposed unit-specific target 

daily emissions rates are discussed 

further in Section VII.B.7 of this 

proposed rule. 

ii. Unit-Specific Emissions Limitations 

Contingent on Assurance Level 

Exceedances 

The second of the proposed trading 

program enhancements intended to 

improve emissions performance at the 

level of individual units is the addition 

of unit-specific secondary emissions 

limitations. The secondary emissions 

limitations would be determined on a 

unit-specific basis according to each 

unit’s individual performance but 

would apply to a given unit only under 

the circumstance where a state’s 

assurance level for a control period has 

been exceeded, the unit is included in 

a group of units to which responsibility 

for the exceedance has been 

apportioned under the program’s 

assurance provisions, and the unit 

operated during at least 10% of the 

hours in the control period. Where these 

conditions for application of a 

secondary emissions limitation to a 

given unit for a given control period are 

met, the unit’s secondary emissions 

limitation would consist of a 

prohibition on NOX emissions during 

the control period that exceed by more 

than 50 tons the NOX emissions that 

would have resulted if the unit had 

achieved an average emissions rate for 

the control period equal to the higher of 

0.10 lb/mmBtu or 125 percent of the 

unit’s lowest average emissions rate for 

any previous control period under any 

CSAPR seasonal NOX trading program 

during which the unit operated for at 

least 10 percent of the hours. 

The proposed secondary emissions 

limitation would be in addition to, not 

in lieu of, the primary emissions 

limitation applicable to each source, 

which would continue to take the form 

of a requirement to surrender a quantity 

of allowances based on the source’s 

emissions, and also in addition to the 

existing assurance provisions, which 

similarly would continue to take the 

form of a requirement for the owners 

and operators of some sources to 

surrender additional allowances when a 

state’s assurance level is exceeded. In 

contrast to these other requirements, the 

proposed unit-specific secondary 

emissions limitation would take the 

form of a prohibition on emissions over 

a specified level, such that any 

emissions by a unit exceeding its 

secondary emissions limitation would 

be subject to potential administrative or 

judicial action and subject to penalties 

and other forms of relief under the 

CAA’s enforcement authorities. The 

reason for proposing this form of 

limitation is that experience under the 

existing CSAPR trading programs has 

shown that, in some circumstances, the 

existing assurance provisions have been 

insufficient to prevent exceedances of a 

state’s assurance level for a control 

period even when the likelihood of an 

exceedance has been foreseeable and the 

exceedance could have been readily 

avoided if certain units had operated 

with emissions rates closer to the lower 

emissions rates achieved in past control 

periods. The assurance levels exist to 

ensure that emissions from each state 

that contribute significantly to 

nonattainment or interfere with 

maintenance of a NAAQS in another 

state are prohibited. North Carolina v. 

EPA, 531 F.3d 896, 906–908 (D.C. Cir. 

2008). EPA’s programs to eliminate 

significant contribution must therefore 

achieve this prohibition, and the new 

evidence of exceedances of the 

assurance provisions demonstrate that 

EPA’s existing approach may not be 

sufficient to accomplish this statutory 

mandate. 

The purpose of including assurance 

levels higher than the state emissions 

budgets in the CSAPR trading programs 

is to provide flexibility to accommodate 

operational variability attributable to 

factors that are largely outside of an 

individual owner’s or operator’s control, 

not to allow owners and operators to 

plan to emit at emissions rates that 

could be anticipated to cause a state’s 

total emissions to exceed the state’s 

emissions budget or assurance level. 

Conduct leading to a foreseeable, readily 

avoidable exceedance of a state’s 

assurance level cannot be reconciled 

with the statutory mandate of the CAA’s 

good neighbor provision that emissions 

‘‘within the state’’ significantly 

contributing to nonattainment or 

interfering with maintenance of a 

NAAQS in another state must be 

prohibited. Because the current CSAPR 

regulations do not expressly prohibit 

such conduct and have proven 

insufficient to deter it in some 

circumstances, the EPA is proposing to 

correct the regulatory deficiency in the 

Group 3 trading program by adding 

secondary emissions limitations that 

cannot be complied with through the 

use of allowances. 

The EPA notes that although the 

principal purpose of the proposed 

secondary emissions limitations is to 

strengthen the assurance provisions, 

which apply on a statewide, seasonal 

basis, the unit-specific structure of the 

new limitations would strengthen the 

incentives for individual units to 

maintain their emissions performance at 

levels consistent with their previously 

demonstrated capabilities. For units 

with existing post-combustion 

emissions controls, the new limitations 

would strengthen the incentives to 

operate and optimize the controls 

continuously, and for units without 

such existing controls, the new 

limitations would strengthen the 

incentives to minimize NOX emissions 

rates through other possible measures 

such as improved maintenance and 

optimization of combustion parameters. 

Continuous operation of postcombustion controls and greater 

attention to the combustion process at 

individual units can be expected to 

reduce some individual units’ emissions 

rates throughout the ozone season, 

including on the days that turn out to 

be most critical for downwind ozone 


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259CSAPR and the CSAPR Update both applied 

to EGUs located in areas within Oklahoma’s borders 

that are now understood to be Indian country, 

consistent with the U.S. Supreme Court’s decision 

in McGirt v. Oklahoma, 140 S. Ct. 2452 (2020) (and 

subsequent case law), clarifying the extent of 

certain Indian country within Oklahoma’s borders. 

However, those rules were issued before the McGirt 

decision. See Section IV.C.2.a. 

levels. Better emissions performance on 

average across the ozone season by 

individual units would also help 

address disparate impacts of pollution 

on overburdened communities 

downwind from some such units. 

The proposed unit-specific secondary 

emissions limitations are discussed 

further in Section VII.B.8 of this 

proposed rule. 

2. Expansion of Geographic Scope 

As part of the proposed approach for 

implementing the NOX emissions 

reductions from EGUs identified as 

necessary to address various states’ 

obligations under the good neighbor 

provision with respect to the 2015 

ozone NAAQS, the EPA is proposing to 

expand the existing geographic scope of 

the existing CSAPR NOX Ozone Season 

Group 3 Trading Program to encompass 

the additional states (and Indian 

country within the borders of such 

states) found to have such obligations 

with respect to EGUs. Specifically, the 

EPA is proposing to expand the Group 

3 trading program to include the 

following states and Indian country 

within the borders of the states: 

Alabama, Arkansas, Delaware, 

Minnesota, Mississippi, Missouri, 

Nevada, Oklahoma, Tennessee, Texas, 

Utah, Wisconsin, and Wyoming. Any 

unit located in a newly added 

jurisdiction that meets the existing 

applicability criteria for the Group 3 

trading program would become an 

affected unit under the program, as 

discussed in Section VII.B.3 of this 

proposed rule. 

CSAPR, the CSAPR Update, and the 

Revised CSAPR Update also applied to 

sources in Indian country, although, 

when those rules were issued, no 

existing EGUs within the regions 

covered by the rules were located on 

lands that the EPA understood at the 

time to be Indian country.259 In contrast, 

within the proposed geographic scope of 

this rulemaking, the EPA is aware of 

areas of Indian country within the 

borders of both Utah and Oklahoma 

with existing EGUs that would meet the 

program’s applicability criteria. Issues 

related to state, tribal, and federal 

jurisdiction with respect to sources in 

Indian country in general and in these 

areas in particular are discussed in 

Section IV.C.2 of this proposed rule. 

EPA’s proposed approach for 

determining a portion of each state’s 

budget for each control period that 

would be set aside for allocation to any 

units in areas of Indian country within 

the state not subject to the state’s CAA 

implementation planning authority is 

discussed in Section VII.B.9 of this 

proposed rule. 

Units in each state would join the 

Group 3 trading program on one of two 

possible dates during the program’s 

2023 control period (that is, the period 

from May 1, 2023, through September 

30, 2023). The reason that two entry 

dates are possible is that, as discussed 

in Section VII.B.11 of this proposed 

rule, the effective date of a final rule in 

this rulemaking may fall after May 1, 

2023. In the case of states (and Indian 

country within the states’ borders) 

whose sources do not currently 

participate in the CSAPR NOX Ozone 

Season Group 2 trading program— 

Delaware, Minnesota, Nevada, Utah, 

and Wyoming—EPA proposes that the 

sources would begin participating in the 

Group 3 trading program on the later of 

May 1, 2023, or the final rule’s effective 

date. However, in the case of the states 

(and Indian country within the states’ 

borders) whose sources do currently 

participate in the Group 2 trading 

program—Alabama, Arkansas, 

Mississippi, Missouri, Oklahoma, 

Tennessee, Texas, and Wisconsin—EPA 

proposes that the sources would begin 

participating in the Group 3 trading 

program on May 1, 2023, regardless of 

the final rule’s effective date, subject to 

transitional provisions designed to 

ensure that the increased stringency of 

the Group 3 trading program as revised 

in this rulemaking would not 

substantively affect the sources’ 

requirements prior to the rule’s effective 

date. This approach provides a simpler 

transition for the sources currently 

covered by the Group 2 trading program 

than the alternative approach of being 

required to switch from the Group 2 

trading program to the Group 3 trading 

program in the middle of a control 

period, and it is the same approach that 

was followed for sources that 

transitioned from the Group 2 trading 

program to the Group 3 trading program 

in 2021 under the Revised CSAPR 

Update. Section VII.B.11 of this 

proposed rule contains further 

discussion of the rationale for this 

approach and the specific proposed 

transitional provisions. 

The EPA notes that under the 

proposed rule, the expanded Group 3 

trading program would include not only 

the 22 states for which the EPA is 

proposing to determine that the required 

control stringency includes, among 

other measures, installation of new postcombustion controls, but also the three 

states—Alabama, Delaware, and 

Tennessee—for which the EPA is 

proposing to determine that the required 

control stringency does not include 

such measures. In previous 

rulemakings, the EPA has chosen to 

combine states in a single multi-state 

trading program only where the selected 

control stringencies were comparable, in 

order to ensure that states did not 

effectively shift their emissions 

reduction requirements to other states 

with less stringent emissions reduction 

requirements by using net out-of-state 

purchased allowances. Although the 

assurance provisions in the CSAPR 

trading programs were designed to 

address the same general concern about 

excessive shifting of emissions 

reduction activities between states, EPA 

chose not to rely on the assurance 

provisions as sufficient to allow for 

interstate trading in situations where the 

states were assigned differing emissions 

control stringencies. 

In this rulemaking, the EPA believes 

the previous concern about the 

possibility that certain states might not 

make the required emissions reductions 

is sufficiently addressed through the 

various proposed enhancements to the 

design of the trading program, even 

where states have been assigned 

differing emissions control stringencies. 

First, the existing assurance provisions 

would be substantially strengthened 

through the addition of the unit-specific 

secondary emissions limitations 

discussed in Sections VII.B.1.c.ii and 

VII.B.8 of this proposed rule. Second, by 

ensuring that individual units operate 

their emissions controls effectively, the 

unit-specific backstop daily emissions 

rate provisions discussed in Sections 

VII.B.1.c.i and VII.B.7 of this proposed 

rule would necessarily also ensure that 

required emissions reductions occur 

within the state. With these 

enhancements to the design of the 

trading program, the EPA does not 

believe it would be necessary for 

sources in Alabama, Delaware, and 

Tennessee to be excluded from the 

revised Group 3 trading program simply 

because their emissions budgets would 

reflect a different selected emissions 

control stringency than the other states 

in the program. 

The EPA requests comment on the 

proposed expansion of the geographic 

scope of the Group 3 trading program to 

include the states and areas of Indian 

country identified above. The EPA also 

requests comment on the proposed 

timing under which the two sets of 

states and Indian country within the 


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260As discussed in Section VII.B.10.b of this 

proposed rule, the EPA expects that any unit that 

becomes subject to the Group 3 trading program 

pursuant to a final rule in this rulemaking and that 

does not already report emissions data to the EPA 

in accordance with 40 CFR part 75 would not be 

required to report emissions data or be subject to 

allowance holding requirements under the Group 3 

trading program until May 1, 2024, because of the 

minimum time interval allowed for installation and 

certification of the required monitoring systems. 

Such a unit would not be taken into account for 

purposes of determining state emissions budgets 

and unit-level allocations under the Group 3 trading 

program until the 2024 control period. As indicated 

in the notes to Table VII.B.3–1 of this proposed 

rule, six of the listed units have reported to the 

Energy Information Administration that they plan 

to retire in 2023. 

respective states’ borders would be 

added to the program. 

3. Applicability and Tentative 

Identification of Newly Affected Units 

The Group 3 trading program 

generally applies to any stationary, 

fossil-fuel-fired boiler or stationary, 

fossil fuel-fired combustion turbine 

located in a covered state (or Indian 

country within the borders of a covered 

state) and serving at any time on or after 

January 1, 2005, a generator with 

nameplate capacity exceeding 25 MW 

and producing electricity for sale, with 

exemptions for certain cogeneration 

units and certain solid waste 

incineration units. To qualify for an 

exemption as a cogeneration unit, an 

otherwise-affected unit generally (1) 

must be designed to produce electricity 

and useful thermal energy through the 

sequential use of energy, (2) must 

convert energy inputs to energy outputs 

with efficiency exceeding specified 

minimum levels, and (3) may not 

produce electricity for sale in amounts 

above specified thresholds. To qualify 

for an exemption as a solid waste 

incineration unit, an otherwise-affected 

unit generally (1) must meet the CAA 

section 129(g)(1) definition of a ‘‘solid 

waste incineration unit’’ and (2) may 

not consume fossil fuel in amounts 

above specified thresholds. The 

complete text of the Group 3 trading 

program’s applicability provisions and 

the associated definitions can be found 

at 40 CFR 97.1004 and 97.1002, 

respectively. 

The EPA is not proposing in this 

rulemaking to revise the existing 

applicability provisions for the Group 3 

trading program. Thus, any unit that is 

located in a newly added state and that 

meets the existing applicability criteria 

for the Group 3 trading program would 

become an affected unit under the 

program. The fact that the applicability 

criteria for all of the CSAPR trading 

programs are identical therefore is 

sufficient to establish that any units that 

are currently required to participate in 

another CSAPR trading program in any 

of the proposed additional states where 

such other programs currently are in 

effect—Alabama, Arkansas, Minnesota, 

Mississippi, Missouri, Oklahoma, 

Tennessee, Texas, and Wisconsin 

(including Indian country within the 

borders of such states)—would also 

become subject to the Group 3 trading 

program. 

In the proposed additional states 

where other CSAPR trading programs 

are not currently in effect—Delaware, 

Nevada, Utah, and Wyoming (including 

Indian country within the borders of 

such states)—units already subject to 

the Acid Rain Program generally would 

also meet the applicability criteria for 

the Group 3 trading program, especially 

if the units are not capable of producing 

both electricity and useful thermal 

energy. Based on a preliminary 

screening analysis of the units in these 

states that currently report emissions 

and operating data to the EPA under the 

Acid Rain Program and that do not 

report the capability to produce both 

electricity and useful thermal energy, 

the Agency believes that all such units 

are likely to meet the applicability 

criteria for the Group 3 trading program. 

Because the applicability criteria for 

the Acid Rain Program and the Group 3 

trading program are not identical, it is 

possible that some units could meet the 

applicability criteria for one program 

but not the other. Using data reported to 

the U.S. Energy Information 

Administration, the EPA has identified 

10 sources in Delaware, Nevada, Utah, 

and Wyoming (and Indian country 

within the borders of the states) with 27 

units that appear to meet the general 

applicability criteria for the Group 3 

trading program and that either (1) do 

not currently report NOX emissions and 

operating data to the EPA under the 

Acid Rain Program or (2) currently 

report NOX emissions and operating 

data to the EPA under the Acid Rain 

Program and also report the capability 

to produce both electricity and useful 

thermal energy. These units are listed in 

Table VII.B.3–1 of this proposed rule. 

For each of these units, the table shows 

the estimated historical heat input and 

emissions data that the EPA proposes to 

use for the unit when determining state 

emissions budgets if the unit is 

ultimately treated as subject to the 

Group 3 trading program.260 The EPA 

currently lacks sufficient information to 

determine whether any of the units 

listed in the table meets all of the 

relevant criteria to qualify for an 

exemption from the Group 3 trading 

program as a cogeneration unit or a 

solid waste incineration unit. 

TABLE VII.B.3–1—SELECTED EXISTING UNITS THAT COULD BE AFFECTED UNDER PROPOSAL

State Facility ID Facility name Unit ID Unit 

type 

Estimated 

ozone 

season 

heat input 

(mmBtu) 

Estimated 

ozone 

season average NOX

emissions 

rate 

(lb/mmBtu) 

Notes 

Delaware ............................... 591 Christiana .............................. 11 ......................... CT ......................... 1,974 0.2594 1 

Delaware ............................... 591 Christiana .............................. 14 ......................... CT ......................... 1,816 0.2027 1 

Delaware ............................... 52193 Delaware City Refinery ......... DCPP2 ................. Boiler .................... 872,824 0.0176 2 

Delaware ............................... 52193 Delaware City Refinery ......... DCPP3 ................. Boiler .................... 2,380,430 0.0169 2 

Delaware ............................... 52193 Delaware City Refinery ......... DCPP4 ................. Boiler .................... 1,374,817 0.0438 2, 3 

Delaware ............................... 52193 Delaware City Refinery ......... MECCU1 .............. CT ......................... 1,679,396 0.0070 2 

Delaware ............................... 52193 Delaware City Refinery ......... MECCU2 .............. CT ......................... 1,679,396 0.0062 2 

Delaware ............................... 7153 Hay Road .............................. 1 ........................... CT ......................... 1,354,272 0.0685 1 

Delaware ............................... 7153 Hay Road .............................. 2 ........................... CT ......................... 1,311,286 0.0663 1 

Nevada .................................. 2322 Clark ...................................... GT4 ...................... CT ......................... 190,985 0.0475 ..........

Nevada .................................. 2322 Clark ...................................... GT5 ...................... CT ......................... 1,455,741 0.0191 ..........

Nevada .................................. 2322 Clark ...................................... GT6 ...................... CT ......................... 1,455,741 0.0187 ..........

Nevada .................................. 2322 Clark ...................................... GT7 ...................... CT ......................... 1,455,741 0.0178 ..........

Nevada .................................. 2322 Clark ...................................... GT8 ...................... CT ......................... 1,455,741 0.0204 ..........

Nevada .................................. 54350 Nev. Cogen. Assoc. 1—Garnet Val.GTA ...................... CT ......................... 660,100 0.0377 2, 4 


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261EPA–HQ–OAR–2020–0272–0094. 

TABLE VII.B.3–1—SELECTED EXISTING UNITS THAT COULD BE AFFECTED UNDER PROPOSAL—Continued 

State Facility ID Facility name Unit ID Unit 

type 

Estimated 

ozone 

season 

heat input 

(mmBtu) 

Estimated 

ozone 

season average NOX

emissions 

rate 

(lb/mmBtu) 

Notes 

Nevada .................................. 54350 Nev. Cogen. Assoc. 1—Garnet Val.GTB ...................... CT ......................... 660,100 0.0387 2, 4 

Nevada .................................. 54350 Nev. Cogen. Assoc. 1—Garnet Val.GTC ...................... CT ......................... 660,100 0.0387 2, 4 

Nevada .................................. 54349 Nev. Cogen. Assoc. 2—Black 

Mtn.

GTA ...................... CT ......................... 749,778 0.0323 2, 4 

Nevada .................................. 54349 Nev. Cogen. Assoc. 2—Black 

Mtn.

GTB ...................... CT ......................... 749,778 0.0370 2, 4 

Nevada .................................. 54349 Nev. Cogen. Assoc. 2—Black 

Mtn.

GTC ...................... CT ......................... 749,778 0.0364 2, 4 

Nevada .................................. 56405 Nevada Solar One ................. HI .......................... Boiler .................... 479,452 0.1667 ..........

Nevada .................................. 54271 Saguaro ................................. CTG1 .................... CT ......................... 1,383,149 0.0314 2 

Nevada .................................. 54271 Saguaro ................................. CTG2 .................... CT ......................... 1,383,149 0.0301 2 

Utah ....................................... 50951 Sunnyside .............................. 1 ........................... Boiler .................... 1,888,174 0.1715 ..........

Wyoming ................................ 56312 Shute Creek .......................... 021A ..................... CT ......................... 1,000,050 0.0081 2 

Wyoming ................................ 56312 Shute Creek .......................... 021B ..................... CT ......................... 1,000,050 0.0093 2 

Wyoming ................................ 56312 Shute Creek .......................... 021C ..................... CT ......................... 1,000,050 0.0084 2 

Table notes: 

1 Unit already reports NOX emissions and heat input data to the EPA under 40 CFR part 75 to comply with SIP requirements. 2 Unit reports capability of producing both electricity and useful thermal energy. 

3 Unit already reports NOX emissions and heat input data to EPA under 40 CFR part 75 for the Acid Rain Program. 4 Unit has reported a planned retirement date of March 2023 to the Energy Information Administration. 

The EPA requests comment on which 

existing units in Delaware, Nevada, 

Utah, and Wyoming and Indian country 

within the borders of such states would 

or would not meet the applicability 

criteria for the Group 3 trading program. 

In addition, with respect to each of the 

units listed in Table VII.B.3–1 of this 

proposed rule, the EPA requests 

comment, with supporting data, on 

whether the unit would or would not 

meet all relevant criteria set forth in 40 

CFR 97.1004 and the associated 

definitions in 97.1002 to qualify for an 

exemption from the trading program as 

a cogeneration unit or a solid waste 

incineration unit (however, see Section 

VI.B.3 of this proposed rule). The EPA 

also requests comment, with supporting 

data, on whether the estimated 

historical heat input and emissions data 

identified for the units in Table VII.B.3– 

1 of this proposed rule are 

representative for the respective units. 

4. New and Revised State Emissions 

Budgets 

The EPA is quantifying budgets or 

budget formulas specific to each year to 

ensure that EGUs continue to be 

incentivized to implement the full 

extent of EPA’s selected control 

stringency for future control periods. By 

doing so, the EPA is accounting for both 

scheduled and not-yet-scheduled fleet 

turnover in future years. For instance, if 

State X’s budget was 5,000 tons in 2023 

but there are 100 tons of emissions from 

a unit scheduled to retire at the end of 

that year and 50 tons expected from a 

new unit coming online by the 

following year, then the state emissions 

budget for 2024 will reflect these 

scheduled changes by establishing a 

budget of 5,000 tons¥100 tons + 50 tons 

= 4,950 tons for the subsequent year. 

In the Revised CSAPR Update, the 

EPA included announced fleet changes 

in state emissions budgets. Several 

commenters applauded the merit of this 

approach and the importance of 

establishing emissions budgets that 

were robust to an evolving fleet while 

noting that ‘‘fleet composition is 

changing constantly and can be 

exceedingly difficult to project’’ leading 

to overstated emissions budgets to the 

extent that future retirements were not 

announced at the time of rule 

promulgation. Commenters added that 

‘‘to address this problem and prevent 

future unknown retirements from 

exacerbating this issue, the final rule 

should include a provision to make 

additional adjustments to the NOX

budgets based on newly discovered fleet 

changes.’’ 261 Commenters were 

suggesting a dynamic budget approach 

where the mitigation measures and 

control stringencies that constituted 

removal of significant contribution 

would be identified in a final rule, but 

the future year state budgets would be 

dynamic as the EPA applied those 

stringency assumptions to future year 

fleet composition data as it became 

available. While the stringency 

(reflected by assumed emissions rate for 

a mitigation technology), would be 

constant, the fleet composition 

(reflected by unit heat input) is 

dynamic. Multiplying the assumed 

emissions rate for each unit by the heat 

input for each unit and summing the 

results to the state level would provide 

a given year’s state emissions budget, 

and thus under this approach the state 

emissions budgets would be dynamic as 

well. 

The EPA is proposing a dynamic 

budget approach in this rule, where 

emissions budgets starting in the 2025 

control period and beyond will be 

determined through ministerial actions 

subsequent to this rule’s promulgation 

and based upon the formula described 

in this rule. This rule will determine the 

mitigation strategies, respective 

emissions rates, and formulas and 

methodologies to be applied to future 

year data, with which the EPA will 

perform ministerial actions to calculate 

emissions budgets for control periods in 

2025 and each year thereafter. (Such 

actions will be publicly announced 

through notices of data availability 

(NODAs), similar to how other periodic 

ministerial actions to implement the 

trading programs are currently handled. 

And as with such other actions, 

interested parties will have the 

opportunity to seek corrections or 

administrative adjudication under 40 

CFR part 78 if they believe any data 

used in making these calculations, or 

the calculations themselves, are in 

error.) In this manner, the state 

emissions budgets ultimately 

implemented for each such future 

control period will be a product of the 

data and formula promulgated in this 


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20116 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

262The EPA notes that historical state-level ozone 

season EGU NOX emissions rates are publicly 

available and quality assured data. They are 

monitored using CEMS or other methodologies 

allowed for use by qualifying units under 40 CFR 

part 75 and are reported to the EPA directly by 

power sector sources. 

action applied to future year reported 

data that is closer to that future control 

period and therefore more 

representative of the fleet for that future 

control period. As such, the budgets 

will more accurately reflect power 

sector composition in that future year 

and will therefore better achieve the 

desired environmental outcome over 

time. 

For instance, 2025 budgets will be 

identified by May 1, 2024, using the 

latest available reported operational 

data at that time (2023 heat input data 

and fleet inventory) along with the 

formulas and emissions rates quantified 

in this rule. Therefore, if a unit retires 

in early 2023 but had not announced its 

upcoming retirement at the time of rule 

finalization, the dynamic budget 

approach would ensure that the budgets 

for future control periods starting in 

2025 would reflect the identified control 

stringency applied to a fleet that reflects 

that retirement. If the EPA took an 

alternative approach of computing the 

2025 budget with available data at the 

time final rule analysis was being 

conducted, this retirement would likely 

not be captured in the 2025 state 

emissions budget, which would lead to 

a budget that did not fully reflect the 

application of the identified control 

stringency. This approach has the 

advantage of mitigating uncertainty 

regarding future retirements, new 

builds, and existing fleet operational/ 

dispatch changes in response to EGU 

inventory changes. 

The example below illustrates the 

effectiveness of the dynamic budget. In 

the preset budget approach for 2026, the 

2026 heat input is estimated based on 

the latest available heat input data at the 

time of rule promulgation (e.g., 2021), 

which cannot reflect a subsequent fleet 

change in heat input values (column 2) 

due to an unanticipated retirement of 

one of the state’s coal-fired units in late 

2023. However, the dynamic budget 

would use 2024 heat input values as 

opposed to the 2021 heat input values 

as the latest representative values to 

inform the 2026 state emissions budget. 

Therefore, the heat input values in 

column 2 under the dynamic scenario 

reflect the change in fleet composition, 

and when multiplied by the relevant 

identified control stringency (to be 

identified when this rule is finalized), 

the corresponding tonnage (15,000 tons) 

summed in column 4 constitutes a state 

budget that better reflects the identified 

control stringency applied to the fleet 

composition for that year as opposed to 

the 17,000 tons in summed in the first 

table. As illustrated in the example, the 

dynamic variable is the heat input 

variable which changes over time to 

reflect the most representative EGU 

fleet. 

The EPA requests comment on this 

dynamic budget approach, including the 

methodology, the start year, and the 

impacts. 

With regard to the state emissions 

budgets for the 2023 and 2024 control 

periods promulgated in this rule, the 

EPA is using the best available data at 

the time of the proposed rule regarding 

retirements and new builds. The EPA 

relies on a compilation of data from 

DOE EIA Form 860 (where facilities 

report their future retirement plans) and 

information included in the Agency’s 

NEEDS database. This information is 

considered to be highly reliable, realworld information that provides the 

EPA with high confidence that such 

retirements will in fact occur. EPA plans 

to update this data on retirements and 

new builds at final rule using the latest 

information available from these sources 

at that time as well as input provided by 

commenter. 

EPA’s emissions budget methodology 

and formula for establishing Group 3 

budgets are described in detail in the 

Ozone Transport Policy Analysis 

Proposed Rule TSD and summarized 

below. 

a. Methodology for Determining Preset 

State Emissions Budgets for the 2023 

and 2024 Control Periods 

For determining state emissions 

budgets, the EPA generally uses 

historical ozone season data from the 

2021 ozone season, the most recent data 

and therefore the most representative of 

near-term fleet conditions. This is 

similar to the approach taken in the 

CSAPR Update where the EPA began 

with 2015 data (the most recent year at 

the time). As in the CSAPR Update, the 

EPA combined historical data with IPM 

data to determine emissions budgets as 

follows: 

(1) Determine a future year baseline—Start 

with the latest reported historical unit-level 

data (e.g., 2021), and adjust any unit data 

where a retirement, a new build, a coal-to-gas 

conversion, or a SCR retrofit is known to 

occur by the baseline year. This results in a 

future year (e.g., 2023) baseline for emissions 

budget purposes. 

(2) Factor in additional emissions controls 

for the selected control stringency for the 

given state in the given year—For the unitlevel emissions control technologies 

identified in this control stringency, adjust 

the baseline unit-level emissions and 

emissions rates. For example, if an SCRcontrolled coal unit had a baseline emissions 

rate greater than 0.08 lb/mmBtu, its 

emissions rate and corresponding emissions 

would be adjusted down to levels reflecting 

its operation at 0.08 lb/mmBtu. 

(3) Incorporate generation shifting—Use 

IPM in a relative way to capture the 

reductions expected from generation shifting 

(constrained to within each state) at the 

representative dollar per ton level 

corresponding to the selected control 

stringency. 

By using historical unit and statelevel NOX emissions rates, heat input, 

and emissions data in the first stage of 

budget setting process outlined above, 

the EPA is grounding its budgets in the 

most recent representative historical 

operation for the covered units.262 This 

dataset is a reasonable starting point for 


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Preset Budget Appraoch (2026) Dynamic Budget Approach (2026) I - • -~~~y • - •• ?.. ~ -·· ~---=-~-~-•~~"-~"'~~~-~~~---- ~-

Preset 

Preset Preset 

Tons (Heat Updated Emissions Updated Tons 

Emissions (Heat Input X Heat Input Rate input X Heat Input Rate Emissions (tBtu) 0b/mmBtu) Emissions (tBtu) 0b/mmBtu) Rate)/2OOO Rate)/2OOO 

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 
Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20117 

the budget-setting process as it reflects 

the latest data reported by affected 

facilities under 40 CFR part 75. The 

reporting requirements include quality 

control measures, verification measures, 

and instrumentation to best record and 

report the data. In addition, the 

designated representatives of EGU 

sources are required to attest to the 

accuracy and completeness of the data. 

The EPA adjusted the 2021 ozoneseason data to reflect committed fleet 

changes under a baseline scenario (i.e., 

announced and confirmed retirements, 

new builds, and retrofits that have 

already occurred). For example, if a unit 

emitted in 2021, but retired in 2022, its 

2021 emissions would not be included 

in the 2023 baseline estimate. For units 

that had no known changes, the 2023 

baseline emissions assumption was the 

actual reported data from 2021. The 

EPA also included known new units 

and scheduled retrofits in this manner. 

Using this method, the EPA arrived at 

a baseline emission, heat input, and 

emissions rate estimate for each unit for 

a future year (e.g., 2023), and then was 

able to aggregate those unit-level 

estimates to state-level totals. These 

state-level totals constituted the state’s 

baseline from an engineering analytics 

perspective. The ozone-season statelevel emissions, heat input, and 

emissions rates for covered sources 

under a baseline scenario were 

determined for each future year 

examined that receives a preset budget 

under this proposed rule (2023 and 

2024). 

The EPA then examined how the 

baseline emissions and emissions rates 

would change under different control 

stringencies for EGUs. For instance, 

under the SCR optimization scenario, if 

a unit was not operating its SCR at 0.08 

lb/mmBtu or lower in the baseline, the 

EPA lowered that unit’s assumed 

emissions rate to 0.08 lb/mmBtu and 

calculated the impact on the unit’s and 

state’s emissions rate and emissions. 

Note that the heat input is held constant 

for the unit in the process, reflecting the 

same level of unit operation compared 

to historical 2021 data. An improved 

emissions rate is then applied to this 

heat input, reflecting control 

optimization. In this manner, the statelevel baseline totals reflecting known 

changes were adjusted to reflect the 

additional application of the assumed 

control technology at a given control 

stringency. 

Finally, the EPA used IPM to capture 

any generation shifting at a given 

control stringency necessary for the 

majority of the respective emissions 

control technology to operate. The EPA 

explains how it accounts for generation 

shifting in more detail in Section VI.B 

of this proposed rule and in the Ozone 

Transport Policy Analysis Proposed 

Rule TSD. In this rule, as a proxy for the 

near-term reductions required in 2023 

and 2024, the EPA has constrained 

generation shifting to occur only withinstate. The EPA also estimates emissions 

reductions associated with generation 

shifting in 2025 and 2026 for purposes 

of the illustrative state budgets, but as 

explained below, the dynamic budget 

process to determine budgets for those 

years will incorporate emissions 

reductions attributable to generation 

shifting through the inclusion of newly 

reported unit-level data from the future 

compliance periods. 

b. Methodology for Determining 

Dynamic State Emissions Budgets for 

Control Periods in 2025 Onwards 

The methodology for determining 

state emissions budgets for later control 

periods (2025 and beyond) is nearly 

identical to the process for quantifying 

preset budgets in 2023 and 2024 

described earlier; it is just applied at a 

later date and applied to the most recent 

representative operational available at 

that time. The EPA will issue by 

ministerial action these dynamic budget 

quantifications approximately 1 year 

before the relevant control period. For 

instance, starting in early 2024, the EPA 

would take the most recent 2023 ozone 

season data, calculate 2025 state 

emissions budgets using the 

methodology below and update its unitlevel and state-level state emissions 

budget files that will be released when 

this rule is finalized (and for which the 

EPA has included in this proposed rule 

current examples for public comment). 

By March 1 of 2024, and each year 

thereafter, the EPA would make 

publicly available (in manner similar to 

data and preliminary computations for 

allocations from new unit set-asides) the 

preliminary state emissions budgets and 

unit-level allocations for the subsequent 

control period (e.g., 2025) and would 

provide stakeholders with a 30-day 

opportunity to submit any objections to 

the updated data and computations. By 

May 1 of 2024, and each year thereafter, 

the EPA would issue the final budgets 

and allowance allocations for the next 

control period (e.g., 2025). 

The differences to each of the formula 

steps to calculate dynamic budgets for 

control periods in 2025 and beyond, 

relative to the calculation of preset 

budgets for the 2023 and 2024 control 

periods, are described later: 

(1) Determine a future year baseline—At 

this step, the EPA would start with the latest 

reported historical unit-level heat input data 

available at that time (e.g., for 2025 state 

emissions budgets, the EPA would use the 

newly available 2023 heat input data rather 

than 2021 heat input data). Doing so would 

capture the latest operational data reflecting 

new builds and retirements. This would 

yield a future year (e.g., 2025) baseline for 

emissions budget purposes. 

(2) Factor in additional emissions controls 

for the selected control stringency for the 

given state in the given year—For the unitlevel emissions reduction measures 

identified in the selected control stringency, 

adjust the baseline unit-level emissions and 

emissions rates. This step would be nearly 

the same for control periods in 2025 and 

beyond as for the 2023 and 2024 control 

periods, the only difference being that as 

described in Section VI.D of this proposed 

rule, for each control period from 2026 

onward, the unit-specific emissions rates 

assumed for all affected states except 

Alabama, Delaware, and Tennessee will 

reflect the selected control stringency that 

incorporates post-combustion control retrofit 

opportunities for the relevant units identified 

in the state emissions budgets and 

calculations appendix to the Ozone 

Transport Policy Analysis Proposed Rule 

TSD. These rates would be defined in this 

rule and would not change subsequently. 

They would not be applied until 2026, based 

on the time necessary to install these 

mitigation technologies as discussed in 

Sections VI.B, VI.C, and VII.A of this 

proposed rule. 

(3) Incorporate generation shifting—This 

step would be automatically captured in 

dynamic budget calculations as generation 

shifting in a compliance scenario would no 

longer have to be projected by IPM and 

incorporated into the state budgets through 

an additional calculation. Instead, it would 

be embodied in the newly reported heat 

input data described above and that is used 

to determine the dynamic budgets. 

Additional details, corresponding 

data and formulas, and examples for the 

dynamic budget are described in the 

Ozone Transport Policy Analysis 

Proposed Rule TSD. 

c. Proposed and Illustrative State 

Emissions Budgets 

For each covered state (and Indian 

country within the state’s borders), 

preset budgets are established for the 

two individual control periods 2023 and 

2024. For 2025 and beyond, the 

dynamic budget formula promulgated in 

this proposed rule would be applied to 

future year data to quantify state 

emissions budgets for those control 

periods. The proposed default 

procedures for allocating the allowances 

from each state budget among the units 

in each state (and Indian country within 

the state’s borders) are described in 

Section VII.B.9 of this proposed rule. 

The amounts of the proposed state 

emissions budgets for the 2023 and 2024 

control periods are shown in Table 

VII.B.4.c–1. Table VII.B.4.c–2 shows 

illustrative state emissions budgets for 


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the 2025 and 2026 control periods 

derived by applying the identified 

control stringency to the most recent 

historical data, but these budgets are 

only illustrative because, under the 

proposal, the implemented state 

emissions budgets for these years will 

be determined at a future date through 

application of the proposed budgetsetting methodology to data that reflect 

the emissions control stringencies 

finalized in the rulemaking combined 

with the latest available data on the 

composition and utilization of the EGU 

fleet. 

TABLE VII.B.4.C–1—PROPOSED CSAPR NOX OZONE SEASON GROUP 3 STATE EMISSIONS BUDGETS FOR THE 2023 AND

2024 CONTROL PERIODS a b

State 

Proposed emissions 

budgets for 2023 

control period 

(tons) 

Proposed emissions 

budgets for 2024 

control period 

(tons) 

Alabama ............................................................................................................................................... 6,364 6,306 

Arkansas .............................................................................................................................................. 8,889 8,889 

Delaware .............................................................................................................................................. 384 434 

Illinois ................................................................................................................................................... 7,364 7,463 

Indiana ................................................................................................................................................. 11,151 9,391 

Kentucky .............................................................................................................................................. 11,640 11,640 

Louisiana .............................................................................................................................................. 9,312 9,312 

Maryland .............................................................................................................................................. 1,187 1,187 

Michigan ............................................................................................................................................... 10,718 10,718 

Minnesota ............................................................................................................................................ 3,921 3,921 

Mississippi ............................................................................................................................................ 5,024 4,400 

Missouri ................................................................................................................................................ 11,857 11,857 

Nevada ................................................................................................................................................. 2,280 2,372 

New Jersey .......................................................................................................................................... 799 799 

New York ............................................................................................................................................. 3,763 3,763 

Ohio ..................................................................................................................................................... 8,369 8,369 

Oklahoma ............................................................................................................................................. 10,265 9,573 

Pennsylvania ........................................................................................................................................ 8,855 8,855 

Tennessee ........................................................................................................................................... 4,234 4,234 

Texas ................................................................................................................................................... 38,284 38,284 

Utah ..................................................................................................................................................... 14,981 15,146 

Virginia ................................................................................................................................................. 3,090 2,814 

West Virginia ........................................................................................................................................ 12,478 12,478 

Wisconsin ............................................................................................................................................. 5,963 5,057 

Wyoming .............................................................................................................................................. 9,125 8,573 

Table Notes: 

aThe state emissions budget calculations pertaining to Tables VII.B.4.c–1 and VII.B.4.c–2 are described in greater detail in the Ozone Transport Policy Analysis Proposed Rule TSD. Budget calculations and underlying data are also available in Appendix A of that TSD. b In the event a final rule in this rulemaking becomes effective after May 1, 2023, the emissions budgets and assurance levels for the 2023 

control period would be adjusted under the rule’s proposed transitional provisions to ensure that the increased stringency of the new budgets 

would apply only after the rule’s effective date, even though the revised Group 3 trading program would be implemented for most sources as of 

the start of the 2023 ozone season on May 1, 2023. The 2023 budget amounts shown in Table VII.B.4.c–1 do not reflect these possible adjustments. The transitional provisions are discussed in Section VII.B.11 of this proposed rule. 

TABLE VII.B.4.C–2—ILLUSTRATIVE CSAPR NOX OZONE SEASON GROUP 3 STATE EMISSIONS BUDGETS FOR THE 2025 

AND 2026 CONTROL PERIODS

State 

Illustrative 

emissions budgets 

for 2025 

control period 

(tons) 

Illustrative 

emissions budgets 

for 2026 

control period 

(tons) 

Alabama ............................................................................................................................................... 6,306 6,306 

Arkansas .............................................................................................................................................. 8,889 3,923 

Delaware .............................................................................................................................................. 434 434 

Illinois ................................................................................................................................................... 7,463 6,115 

Indiana ................................................................................................................................................. 8,714 7,791 

Kentucky .............................................................................................................................................. 11,134 7,573 

Louisiana .............................................................................................................................................. 9,179 3,752 

Maryland .............................................................................................................................................. 1,187 1,189 

Michigan ............................................................................................................................................... 10,759 6,114 

Minnesota ............................................................................................................................................ 3,910 2,536 

Mississippi ............................................................................................................................................ 4,400 1,914 

Missouri ................................................................................................................................................ 10,456 7,246 

Nevada ................................................................................................................................................. 2,372 1,211 

New Jersey .......................................................................................................................................... 799 799 

New York ............................................................................................................................................. 3,763 3,238 

Ohio ..................................................................................................................................................... 8,369 8,586 

Oklahoma ............................................................................................................................................. 9,393 4,275 

Pennsylvania ........................................................................................................................................ 8,855 6,819 

Tennessee ........................................................................................................................................... 4,008 4,008 


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263 531 F.3d at 908. 

264As discussed in Section VII.B.8 of this 

proposed rule, the EPA is also proposing to 

establish a new secondary emissions limitation for 

individual units that would apply in situations 

where an exceedance of the relevant state’s 

assurance level has occurred. 

265See 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. 

TABLE VII.B.4.C–2—ILLUSTRATIVE CSAPR NOX OZONE SEASON GROUP 3 STATE EMISSIONS BUDGETS FOR THE 2025 

AND 2026 CONTROL PERIODS—Continued 

State 

Illustrative 

emissions budgets 

for 2025 

control period 

(tons) 

Illustrative 

emissions budgets 

for 2026 

control period 

(tons) 

Texas ................................................................................................................................................... 36,619 21,946 

Utah ..................................................................................................................................................... 15,146 2,620 

Virginia ................................................................................................................................................. 2,948 2,567 

West Virginia ........................................................................................................................................ 12,478 10,597 

Wisconsin ............................................................................................................................................. 4,198 3,473 

Wyoming .............................................................................................................................................. 8,573 4,490 

5. Variability Limits and Assurance 

Levels 

Like each of the other CSAPR trading 

programs, the Group 3 trading program 

currently includes assurance provisions 

designed to limit the total emissions 

from the sources in each state (and 

Indian country within the state’s 

borders) in each control period to an 

amount close to the state’s emissions 

budget for the control period, consistent 

with the good neighbor provision’s 

requirement that required emissions 

reductions must be achieved within the 

state, while allowing some flexibility 

beyond the emissions budget to 

accommodate year-to-year operational 

variability beyond sources’ reasonable 

ability to control. For each state, the 

assurance provisions establish an 

assurance level for each control period, 

defined as the sum of the state’s 

emissions budget for the control period 

plus a variability limit, which under the 

existing Group 3 trading program 

regulations is 21 percent of the relevant 

state emissions budget. The purpose of 

the variability limit is to account for 

year-to-year variability in EGU 

operations, which can occur for a 

variety of reasons including changes in 

weather patterns, changes in electricity 

demand, and disruptions in electricity 

supply from other units or from the 

transmission grid. Because of the need 

to account for such variability in 

operations of each state’s EGUs, the fact 

that emissions from the state’s EGUs 

may exceed the state’s emissions budget 

for a given control period is not treated 

as inconsistent with satisfaction of the 

state’s good neighbor obligations as long 

as the total emissions from the EGUs 

remain below the state’s assurance level. 

Emissions from a state’s EGUs above the 

state’s emissions budget but below the 

state’s assurance level are treated in the 

same manner as emissions below the 

state’s emissions budget in that such 

emissions are subject to the same 

requirement to surrender allowances at 

a ratio of one allowance per ton of 

emissions. In contrast, emissions above 

the state’s assurance level for a given 

control period are strongly discouraged 

as inconsistent with the state’s good 

neighbor obligations and are subject to 

an overall 3-for-1 allowance surrender 

ratio. The establishment of assurance 

levels with associated extra allowance 

surrender requirements was intended to 

respond to the D.C. Circuit’s holding in 

North Carolina requiring the EPA to 

ensure within the context of an 

interstate trading program that sources 

in each state are required to address 

their good neighbor obligations within 

the state and may not simply shift those 

obligations to other states by failing to 

reduce their own emissions and instead 

surrendering surplus allowances 

purchased from sources in other 

states.263

In this rulemaking, the EPA is not 

proposing to alter the basic structure of 

the Group 3 trading program’s assurance 

provisions, which would continue to set 

an assurance level for each control 

period equal to the state’s emissions 

budget for the control period plus a 

variability limit and would continue to 

apply a 3-for-1 surrender ratio to 

emissions exceeding the state’s 

assurance level.264 Each assurance level 

also would continue to apply to the 

collective emissions of all units within 

the state and Indian country within the 

state’s borders.265 For the 2023 and 2024 

control periods, the EPA proposes to 

retain the Revised CSAPR Update’s 

methodology for determining each 

state’s variability limit as 21 percent of 

the state’s emissions budget for the 

control period, except that because the 

EPA is proposing to revise the state 

emissions budgets for these control 

periods, the EPA proposes to determine 

the corresponding variability limits as 

21 percent of the revised budgets. 

However, for control periods after 2024, 

the EPA is proposing a change to the 

methodology for determining the 

variability limits. Specifically, the EPA 

proposes to determine each state’s 

variability limit for the control periods 

in 2025 or a later year so that, instead 

of always multiplying the state’s 

emissions budget for the control period 

by a value of 21 percent, the percentage 

value used would be the higher of 21 

percent or the percentage (if any) by 

which the total reported heat input of 

the state’s affected EGUs in the control 

period exceeds the total reported heat 

input of the state’s affected EGUs as 

reflected in the state’s emissions budget 

for the control period. For example, if 

the total reported heat input of the 

state’s covered sources for the 2025 

control period was 90 percent or 110 

percent of the total reported heat input 

of the state’s covered sources for the 

2023 control period (i.e., the heat input 

the EPA would have used in computing 

the state’s 2025 emissions budget), then 

the state’s variability limit for the 2025 

control period would be 21 percent of 

the state’s emissions budget, while if the 

total reported heat input of the state’s 

covered sources for the 2025 control 

period was 130 percent of the total 

reported heat input of the state’s 

covered sources for the 2023 control 

period, then the state’s variability limit 

for the 2025 control period would be 30 

percent of the state’s emissions budget. 

The EPA expects that the minimum 21 

percent would apply in almost all 

instances, and that the alternative, 

higher percentage value would apply 

only in control periods where 

operational variability caused an 

extreme increase relative to the earlier 

year used in setting the state’s emissions 

budget, which would be a situation 


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20120 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

266For details on the original variability analysis 

for 26 states over the 2000–2010 period, including 

a description of the methodology, see the Power 

Sector Variability Final Rule TSD from the CSAPR 

(EPA–HQ–OAR–2009–0491–4454). For the updated 

variability analysis for twelve states for the 2000– 

2019 period, see the Excel file ‘‘Historical 

Variability in Heat Input 2000 to 2019.xls.’’ Both 

documents are available in the docket for this 

proposal. 

267See 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. 

meriting a temporarily higher variability 

limit and assurance level. 

The purpose of the proposed revision 

to the variability limits is to better align 

the variability limits for successive 

control periods with the regularly 

updated heat input data that would be 

used in the proposed process for 

dynamically setting the state emissions 

budgets. Under EPA’s proposed budgetsetting process, each emissions budget 

would be computed using the latest 

available reported heat input, which for 

each budget set for a control period in 

2025 or a later year would be the heat 

input for the control period two years 

before the control period whose budget 

is being determined (for example, the 

state emissions budgets for the 2025 

control period would be computed in 

early 2024 using the reported heat input 

for the 2023 control period). The 

proposed revised variability limits 

would be well coordinated with the 

budgets established using this dynamic 

budgeting process, because the 

percentage change in the actual heat 

input for the control period relative to 

the earlier-year heat input used in 

computing the state’s emissions budget 

would be an appropriate measure of the 

degree of operational variability actually 

experienced by the state‘s EGUs in the 

control period relative to the assumed 

operating conditions reflected in the 

state’s budget. Setting a variability limit 

in this manner would be entirely 

consistent with the overall purpose of 

including variability limits in the 

assurance provisions. 

The reason the EPA is proposing to 

use the higher of a fixed 21% or the 

percentage change in heat input 

computed as just described is that the 

EPA believes that, for operational 

planning purposes, it can be useful for 

sources to know in advance of the 

control period a minimum value for 

what the variability limit could turn out 

to be. Because a state’s actual total heat 

input for a control period is not known 

until after the end of the control period, 

this proposed revision would have the 

consequence that the state’s final 

variability limit and assurance level for 

the control period also would not be 

known until after the control period. 

However, because the proposed rule 

provides that the variability limit would 

always be at least 21 percent, the 

sources in a state would be able to rely 

for planning purposes on the knowledge 

that the assurance level would always 

be at least 121 percent of the state’s 

emissions budget for the control period. 

Advance knowledge of the minimum 

possible amount of the assurance level 

can be useful to sources, because one 

way a source can be confident that it 

will never incur the 3-for-1 allowance 

surrender ratio owed for emissions 

exceeding its state’s assurance level is to 

plan its operations so as to never allow 

its own emissions to exceed its own 

share of the state’s assurance level for 

the control period. Knowing that the 

variability limit would always be at 

least 21 percent would provide sources 

with values they could use for such 

planning purposes. 

The EPA believes that 21 percent is a 

reasonable value to use as the fixed 

variability limit for the 2023 and 2024 

control periods and as the minimum 

variability limit for the control periods 

in 2025 and later years. To determine 

appropriate variability limits for the 

trading programs established in CSAPR, 

the EPA analyzed historical state-level 

heat input variability over the period 

from 2000 through 2010 as a proxy for 

emissions variability, assuming constant 

emissions rates. See 76 FR 48265. Based 

on that analysis, the variability limits 

for ozone season NOX in both CSAPR 

and the CSAPR Update were set at 21 

percent of each state’s budget, and these 

variability limits for the NOX ozone 

season trading programs were then 

codified in 40 CFR 97.510 and 40 CFR 

97.810, along with the respective state 

budgets. For the Revised CSAPR 

Update, the EPA performed an updated 

variability analysis for the twelve states 

being moved into the Group 3 trading 

program in that rulemaking, evaluating 

historical state-level heat input 

variability over the period from 2000 

through 2019. The updated analysis 

again resulted in a variability estimate 

of 21 percent. The EPA also considered 

shorter time periods for the updated 

analysis and found that the resulting 

variability estimates were not especially 

sensitive to the particular time period 

analyzed.266 A further updated analysis 

for this rulemaking again results in a 

variability estimate of 21 percent for 

most states, and although the historical 

analysis indicates higher percentages for 

the two states with the smallest total 

heat input figures in this analysis— 

Delaware and New Jersey—the EPA 

does not consider it appropriate to raise 

the variability limit percentage beyond 

21 percent for all other states based on 

the analytic results for these states, 

where small absolute heat input figures 

have resulted in larger variability 

percentages.267 Based on the consistent 

conclusions of these multiple analyses, 

the EPA proposes to continue using 21 

percent as the fixed variability limit 

percentage for the 2023 and 2024 

control periods and as the minimum 

value in the revised approach for 

establishing variability limits for the 

control periods in 2025 and later years. 

The EPA requests comment on the 

proposed rule to set variability limits for 

the 2023 and 2024 control periods as 21 

percent of the respective revised state 

emissions budgets, consistent with the 

methodology used to determine the 

variability limits for these control 

periods set in the Revised CSAPR 

Update. In addition, the EPA requests 

comment on whether to set higher 

variability limits for Delaware and New 

Jersey for 2023 and 2024 based on the 

results of the most recent variability 

analysis. The EPA also requests 

comment on the proposed rule to 

establish a revised methodology for 

setting variability limits for all states for 

control periods in 2025 and later years, 

as discussed in this section. 

6. Annual Recalibration of Allowance 

Bank 

As discussed in Section VII.B.1.b of 

this proposed rule, in this rulemaking, 

the EPA is proposing two revisions to 

the Group 3 trading program designed to 

better maintain the control stringency 

selected in the final rule in this 

rulemaking. The first proposed revision, 

discussed Section VII.B.4 of this 

proposed rule, is to adopt a dynamic 

budget-setting methodology that would 

allow state emissions budgets in future 

years to reflect more accurate 

information about the composition and 

utilization of the EGU fleet. The second, 

complementary, proposed revision is to 

recalibrate the bank of unused 

allowances each control period in order 

to prevent allowance surpluses in 

individual control periods from 

accumulating and adversely impacting 

the ability of the trading program in 

future control periods to maintain the 

selected control stringency identified in 

the rulemaking as necessary to address 

states’ good neighbor obligations with 

respect to the 2015 ozone NAAQS. 

The EPA proposes to begin the bank 

recalibration process starting with the 

2024 control period, after the 

compliance process for the 2023 control 

period for all current and newly added 

states in the Group 3 trading program 


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268See 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. 

has been completed. The recalibration 

process for each control period would 

be carried out on or shortly after August 

1 of that control period, two months 

after the compliance deadline for the 

previous control period, making the 

proposed date of the first recalibration 

August 1, 2024. The recalibrations could 

not take place significantly earlier than 

August 1 each year because compliance 

for the previous control period would 

not be completed until after June 1. 

However, because data on the amounts 

of allowances held are publicly 

available and the total quantity of 

allowances needed for compliance for 

the previous control period would be 

known shortly after the end of that 

control period, sources and other market 

participants would be able to ascertain 

with reasonable accuracy shortly after 

the end of each control period what 

degree of recalibration to expect for the 

next control period, even if the 

recalibration would not actually be 

carried out until the following August. 

Before undertaking a recalibration 

process each control period, the EPA 

would first determine whether the total 

amount of all banked Group 3 

allowances from previous control 

periods held in all facility accounts and 

general accounts in the Allowance 

Management System accounts exceeds 

the target bank amount. (For this 

purpose, no distinction would be made 

between banked Group 3 allowances 

issued from the state emissions budgets 

for previous control periods and banked 

Group 3 allowances issued through the 

conversion of previously banked Group 

2 allowances.) If the total amount of 

banked Group 3 allowances does not 

exceed the target bank amount, the EPA 

would not carry out any recalibration 

for that control period. If the total 

amount of unused allowances does 

exceed the target bank amount, the EPA 

would determine for each account with 

holdings of banked Group 3 allowances 

the account-specific recalibrated 

amount of allowances, computed as the 

target bank amount multiplied by the 

account’s total holdings of banked 

Group 3 allowances and divided by the 

total amount of banked Group 3 

allowances in all accounts, rounded up 

to the nearest allowance. Finally, the 

EPA would deduct from each account 

any banked Group 3 allowances 

exceeding the account’s recalibrated 

amount of banked allowances. 

As the target bank amount used in the 

recalibration process for each control 

period, the EPA proposes to use an 

amount determined as 10.5 percent of 

the sum of the state emissions budgets 

for the control period, or half of the sum 

of the states’ proposed minimum 

variability limits. The EPA has two 

reasons for proposing this amount. First, 

in the transition from CSAPR to the 

CSAPR Update, where the EPA set a 

target bank amount 1.5 times the sum of 

the variability limits, and in the 

transition from the CSAPR Update to 

the Revised CSAPR Update, where the 

EPA set a target bank amount of 1.0 

times the sum of the variability limits, 

in each case the initial bank proved 

larger than necessary, as total emissions 

of all sources in the program were less 

than the budgets. Second, an analysis of 

year-to-year variability of heat input for 

the region covered by this proposed rule 

suggests that the regional heat input for 

an individual year can be expected to 

vary by up to 10.5 percent above or 

below the central trend with 95% 

confidence. This variability analysis is 

an application to the entire region of the 

variability analysis EPA has performed 

for individual states to establish the 

variability limit of 21 percent for the 

states in the trading program.268 When 

the analysis is performed at the regional 

level, the data show less year-to-year 

variation than when the analysis is 

performed at the individual state level. 

Within the trading program structure, it 

is logical to use variability analyzed at 

the level of individual states to set the 

variability limits, which apply at the 

level of individual states, while using 

variability analyzed at the level of the 

overall region to set a target level for a 

bank, which will apply at the level of 

the overall program. 

The annual bank recalibrations will 

help maintain the control stringency 

determined to be necessary to address 

states’ good neighbor obligations for the 

2015 ozone NAAQS. Moreover, the 

proposed recalibrations are less 

complex than alternative approaches 

would be. For example, the NOX Budget 

Trading Program established in the NOX

SIP Call also contained provisions 

designed to prevent excessive 

accumulations of banked allowances on 

program stringency, but those 

provisions—under the name 

‘‘progressive flow control’’—introduced 

uncertainty as to whether banked 

allowances would be usable to offset 

one ton of emissions or less than one 

ton of emissions in the current control 

period. The EPA considers the 

recalibration mechanism proposed here 

to be simpler with less associated 

uncertainty. 

Finally, the EPA observes that the 

proposed recalibration mechanism is 

entirely consistent with the Agency’s 

existing authority under 40 CFR 

97.1006(c)(6) to ‘‘terminate or limit the 

use and duration’’ of any Group 3 

allowance ‘‘to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act.’’ The 

Administrator proposes to determine 

that the recalibrations are both 

necessary and appropriate to ensure that 

the control stringency selected in this 

rulemaking is maintained and states’ 

good neighbor obligations with respect 

to the 2015 ozone NAAQS are 

addressed. 

The EPA requests comment on the 

proposed bank recalibration provisions 

and the proposed use of a target bank 

amount computed as 10.5 percent times 

the sum of the state emissions budgets 

for each control period. 

7. Unit-Specific Backstop Daily 

Emissions Rates 

While the identified EGU emissions 

reductions in Section VI of this 

proposed rule are incentivized and 

secured primarily through the 

corresponding seasonal state emissions 

budgets (expressed as a seasonal 

tonnage limit for all covered EGUs 

within a state’s borders) described 

earlier, the EPA is also incorporating 

backstop daily emissions rates of 0.14 

lb/mmBtu for coal-fired steam units 

serving generators with nameplate 

capacity greater than or equal to 100 

MW in covered states. The backstop 

emissions rates will first apply in 2024 

for coal-fired steam units with existing 

SCR controls, and in 2027 for coal-fired 

steam units currently without SCR 

controls. For a unit that exceeds its 

applicable backstop daily emissions rate 

on any day, all emissions on that day 

exceeding the emissions that would 

have occurred at the backstop daily 

emissions rate will be subject to a 3-for1 allowance surrender ratio instead of 

the normal 1-for-1 allowance surrender 

ratio. See Appendix A of the Ozone 

Transport Policy Proposed Rule TSD for 

a list of coal-fired steam units serving 

generators larger than or equal to 100 

MW in covered states for which the 

identified backstop emissions rate 

would apply starting in either 2024 or 

2027. 

The EGU NOX Mitigation Strategies 

Proposed Rule TSD describes the 

methodology for deriving the 0.14 lb/ 

mmBtu daily rate limit in more detail. 

The methodology is summarized as 

follows. First, consistent with 


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269See 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.’’ 

270See 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. 

271See 40 CFR 423.11(w). 

272See 40 CFR 257.103(b). 

273See 40 CFR 51.308(f). 

274 Information on the assurance level 

exceedances in the 2019 and 2020 control periods 

is available in the final notices concerning EPA’s 

administration of the assurance provisions for those 

control periods. 85 FR 53364 (August 28, 2020); 86 

FR 52674 (September 22, 2021). The EPA will 

publish an analogous final notice for the 2021 

control period by October 1, 2022, and will also 

publish a preliminary notice by August 1, 2022. At 

this time, information on the relevant Missouri 

assurance level for the 2021 control period is 

available at 40 CFR 97.806(c)(2) and 97.810 and 

preliminary data on Missouri units’ emissions of 

stakeholders’ focus on providing daily 

assurance of control operation, EPA 

determined that daily (as opposed to 

hourly or monthly) was an appropriate 

time metric for backstop emissions rate 

limits instituted to ensure operation of 

controls on high ozone days. The EPA 

derived the 0.14 lb/mmBtu daily rate 

limit by determining the particular level 

of a daily rate that would be comparable 

in stringency to the 0.08 lb/mmBtu 

seasonal emissions rate that the Agency 

has identified as reflecting SCR 

optimization at existing units.269 The 

EPA first conducted an empirical 

exercise using reported daily emissions 

rate data from existing, SCR-controlled 

coal units that were emitting at or below 

0.08 lb/mmBtu on a seasonal average 

basis. Recognizing that this seasonal rate 

reflects the average across a unit’s range 

of varying daily rates reflecting different 

operation conditions, including some 

occasions when the SCR control may 

not be operating or may not be fully 

optimized, the EPA identified the upper 

end of the daily emissions rate range for 

these units. When the EPA examined 

the daily emissions rate pattern for these 

units considered to be optimizing their 

SCRs on a seasonal basis, the EPA 

observed that over 95 percent of the 

time, their daily rates were below 0.14 

lb/mmBtu. In addition, for these units, 

less than 1 percent of their seasonal 

emissions would exceed this daily rate 

limit. 

The EPA conducted this analysis to be 

consistent with the methodology 

developed in the 2014 1-hr SO2

attainment area guidance for identifying 

‘‘comparably stringent’’ emissions rates 

over varying time-periods.270 Appendix 

C of that guidance describes a series of 

steps that involve: (1) Compiling 

emissions data to reflect a distribution 

of emissions rates with various 

averaging times, (2) determining the 

99th percentile of the average emissions 

values compiled in the previous step, 

and then (3) applying ‘‘adjustment 

factors’’ or ratios of the 99th percentile 

values to emissions rates to convert 

them (usually from a short-term rate to 

a longer-term rate). In this case, the EPA 

applied the methodology in reverse to 

convert a longer-term limit (the seasonal 

rate of 0.08 lb/mmBtu which was 

assumed to be equal to a 30-day rate of 

0.08 lb/mmBtu) to a comparably 

stringent short-term limit (a daily rate of 

0.14 lb/mmBtu). The EPA requests 

comment on the proposed incorporation 

of a backstop daily emissions rate 

element into the Group 3 trading 

program and on the proposed 

methodology for determining the daily 

emissions rate of 0.14 lb/mmBtu. 

In addition, the EPA requests 

comment on application of the backstop 

daily emissions rates in the event that 

an affected unit finds it more economic 

to retire shortly after the start of the 

2027 ozone season in lieu of investing 

in new NOX post-combustion control 

technology. This proposed rule’s state 

emissions budgets would require 

emissions reductions starting in 2026 

commensurate with SCR retrofits at 

these units regardless of when these 

unit-level backstop rates are 

subsequently imposed. The EPA 

recognizes that such retrofits in practice 

may be less environmentally efficient 

compared to imminent retirement that 

would potentially yield lower 

cumulative emissions of NOX and 

multiple other pollutants over time. The 

EPA also recognizes that several coalfired EGUs have been considering 

retirement by 2028 under compliance 

pathways available under Clean Water 

Act effluent guidelines 271 and the coal 

combustion residuals rule under the 

Resource Conservation and Recovery 

Act.272 2028 also represents the end of 

the second planning period under the 

Regional Haze program, and thus is a 

significant year in states’ planning of 

strategies to make reasonable progress 

towards natural visibility at Class I 

areas.273 To facilitate a potentially 

economic and environmentally superior 

unit-level compliance response across 

these programs that nonetheless 

maintains the NOX reductions required 

by the state budgets from 2026 forward 

in this proposed rule, the EPA is 

requesting comment on potentially 

deferring the application of the backstop 

daily rate for large coal EGUs that 

submit written attestation to the EPA 

that they make an enforceable 

commitment to retire by no later than 

the end of calendar year 2028. EPA 

anticipates that units failing to retire 

contrary to their attestation would 

become subject to the backstop 

emissions rate in the 2029 ozone season, 

and would likely be subject to other 

appropriate enforcement proposed rule 

under the Clean Air Act or other 

relevant authorities. 

8. Unit-Specific Emissions Limitations 

Contingent on Assurance Level 

Exceedances 

As emphasized by the D.C. Circuit in 

its decision invalidating CAIR, under 

the CAA’s good neighbor provision, 

emissions ‘‘within the State’’ that 

contribute significantly to 

nonattainment or interfere with 

maintenance of a NAAQS in another 

state must be prohibited. North Carolina 

v. EPA, 531 F.3d 896, 906–908 (D.C. Cir. 

2008). The CAIR trading programs 

contained no provisions limiting the 

degree to which a state could rely on net 

purchased allowances as a substitute for 

making in-state emissions reductions, 

an omission which the court found was 

inconsistent with the requirements of 

the good neighbor provision. Id. In 

response to that holding, the EPA 

established the CSAPR trading 

programs’ assurance provisions to 

ensure that, in the context of a flexible 

trading program, the emissions 

reductions required under the good 

neighbor provision in fact will take 

place within the state. The EPA believes 

the assurance provisions have generally 

been successful in achieving that 

objective, as evidenced by the fact that 

since the assurance provisions took 

effect in 2017, out of the nearly 300 

instances where a given state’s 

compliance with the assurance 

provisions of a given CSAPR trading 

program for a given control period has 

been assessed, a state’s collective 

emissions have exceeded the applicable 

assurance level only four times. 

Unfortunately, the EPA also 

recognizes that the assurance 

provisions’ very good historical 

compliance record is not good enough. 

The four past exceedances all occurred 

under the Group 2 trading program: 

Sources in Mississippi collectively 

exceeded their applicable assurance 

levels in the 2019 and 2020 control 

periods, and sources in Missouri 

collectively exceeded their applicable 

assurance levels in the 2020 and 2021 

control periods.274 Both of the 


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NOX during the 2021 ozone season are available at 

ampd.epa.gov. 

275The EPA believes that the occurrence of 

avoidable assurance level exceedances under the 

Group 2 trading program, combined with the 

express statutory directive that good neighbor 

obligations must be addressed ‘‘within the state,’’ 

and through ‘‘prohibition,’’ would also provide a 

sufficient legal basis for the Agency to promulgate 

the same revisions to the assurance provisions for 

all the other CSAPR trading programs. The EPA is 

not proposing to do so at this time because the 

Agency has seen no reason to expect exceedances 

of the assurance levels under any of the other 

CSAPR trading programs by any of the states that 

will remain subject to the respective trading 

programs after this rulemaking, except possibly by 

Missouri under the CSAPR NOX Annual Trading 

Program. The EPA expects that reductions in 

Missouri’s seasonal NOX emissions sufficient to 

comply with the proposed provisions of the revised 

Group 3 trading program, including the secondary 

emissions limitations, would also prevent 

exceedances of Missouri’s currently applicable 

assurance level for annual NOX emissions. 

exceedances by Missouri sources could 

easily have been avoided if the owner 

and operator of several SCR-equipped, 

coal-fired steam units had not chosen to 

idle the units’ controls and rely instead 

on net out-of-state purchased 

allowances. The exceedances were 

large, and ample quantities of 

allowances to cover the resulting 3-for1 allowance surrender requirements 

were purchased in advance, suggesting 

that the assurance level exceedances 

may have been anticipated as a 

possibility. In the case of the 

Mississippi exceedances, the 

exceedances were smaller, operational 

variability (manifesting as increased 

heat input) appears to have been a 

material contributing factor, and the 

EPA has not concluded that the owners 

and operators anticipated the 

exceedances. However, an additional 

contributing factor was the fact that 

several large, gas-fired steam units 

without SCR controls emitted NOX at 

average rates much higher than the 

average emissions rates the same units 

had achieved in previous control 

periods. In short, while the Missouri 

exceedances appear far more significant, 

EPA’s analysis indicates that all four 

past exceedances could have been 

avoided if the units most responsible 

had achieved emissions rates more 

comparable to the same units’ previous 

performance. In EPA’s view, the 

operation of the Missouri units in 

particular—although not prohibited by 

the current regulatory requirements— 

cannot be reconciled with the statutory 

requirements of the good neighbor 

provision. The fact that such operation 

is not prohibited by the current 

regulations therefore indicates a 

deficiency in the current regulatory 

requirements. 

To correct the deficiency in the 

regulatory requirements, the EPA 

proposes in this rulemaking to revise 

the Group 3 trading program regulations 

to establish an additional emissions 

limitation to more effectively deter 

avoidable assurance level exceedances. 

Because the pollutant involved is ozone 

season NOX and the particular sources 

for which deterrence is most needed are 

located in states that are proposed to 

transition soon from the Group 2 trading 

program to the Group 3 trading program, 

the EPA is proposing to promulgate the 

strengthening provisions as revisions to 

the Group 3 trading program regulations 

rather than the Group 2 trading program 

regulations.275

The two current emissions-related 

compliance requirements in the Group 3 

trading program regulations are both 

structured in the form of requirements 

to hold allowances. The first 

requirement applies at the source level: 

Specifically, at the compliance deadline 

after each control period, the owners 

and operators of each source covered by 

the program must surrender a quantity 

of allowances that is determined based 

on the emissions from the units at the 

source during the control period. The 

second requirement applies at the 

designated representative level (which 

typically is the owner or operator level): 

If the state’s sources collectively emit in 

excess of the state’s assurance level, the 

owners and operators of each set of 

sources determined to have contributed 

to the exceedance must surrender an 

additional quantity of allowances. As 

long as a source’s owners and operators 

comply with these two allowance 

surrender requirements (and meet 

certain other requirements not related to 

the amounts of the sources’ emissions), 

they are in compliance with the 

program. 

In light of the operation of the 

Missouri sources, the EPA is doubtful 

that strengthening the assurance 

provisions by increasing allowance 

surrender requirements at the unit, 

source, or designated representative 

level would create a sufficient deterrent. 

Accordingly, the EPA is proposing 

instead to add a new, unit-level 

emissions limitation structured as a 

prohibition to emit NOX in excess of a 

defined amount. A violation of the 

prohibition would not trigger additional 

allowance surrender requirements 

beyond the surrender requirements that 

would otherwise apply, but would 

trigger the possible application of the 

CAA’s enforcement authorities. Because 

the purpose of the new unit-level 

emissions limitation would be to deter 

conduct causing exceedances of a state’s 

assurance level, the EPA proposes to 

condition applicability of the new 

limitation on (1) the occurrence of an 

exceedance of the state’s assurance level 

for the control period, and (2) the 

apportionment of at least some of the 

responsibility for the assurance level 

exceedance to the set of units 

represented by the unit’s designated 

representative. Apportionment of 

responsibility for the assurance level 

exceedance would be carried out 

according to the existing assurance 

provision procedures and would 

therefore depend on the designated 

representative’s shares of both the 

state’s total emissions for the control 

period and the state’s assurance level for 

the control period. The new emissions 

limitation would be in addition to, not 

in lieu of, the other requirements of the 

Group 3 trading program. This point 

would be made explicit by relabeling 

the source-level allowance holding 

requirement, currently called the 

‘‘emissions limitation,’’ as the ‘‘primary 

emissions limitation’’ and labeling the 

new unit-level requirement as the 

‘‘secondary emissions limitation.’’ (The 

regulations label the designated 

representative-level requirement as 

‘‘compliance with the . . . assurance 

provisions.’’) 

The EPA proposes to define the unitlevel secondary emissions limitation by 

formula to reflect the amount of 

additional NOX emissions caused by the 

unit’s deviation from a benchmark 

seasonal average NOX emissions rate 

during the control period, where the 

benchmark seasonal average NOX

emissions rate for the unit would be 

based on emissions rates the unit has 

achieved in the past plus a 25 percent 

margin. The EPA also proposes to use a 

floor for past performance of 0.08 lb/ 

mmBtu (yielding 0.10 lb/mmBtu when 

the 25 percent margin is added), 

exclude control periods where the unit 

operated in less than 10 percent of the 

hours (in order to avoid data that might 

be unrepresentative), and screen out 

instances where the amount of 

additional emissions caused by the poor 

performance is less than 50 tons. 

Specifically: 

• The EPA proposes to define a unit’s 

secondary emissions limitation for a 

control period, in tons of NOX, as the 

sum of 50 tons plus the product of (1) 

the unit’s benchmark seasonal average 

emissions rate times (2) the unit’s actual 

heat input for the control period, except 

that if the unit operated during less than 

10 percent of the hours in the control 

period, no secondary emissions 

limitation would be defined for the unit 

for that control period. 

• The EPA proposes to calculate the 

benchmark seasonal average NOX


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276 In proposing a formulation for a benchmark 

rate for the specific regulatory purpose of defining 

a secondary emissions limitation under the Group 

3 trading program, the EPA is not expressing a view 

that the same formulation of a benchmark rate 

would be suitable for any other regulatory purpose. 

277The units qualifying for allocations from a 

new unit set-aside may include not only units that 

have recently started operating but also units that 

previously received, but are no longer eligible to 

receive, allocations from the unreserved portion of 

the budget as ‘‘existing’’ units. 

emissions rate for a unit for this 

purpose, in lb NOX/mmBtu, as the 

higher of (1) 0.10 lb/mmBtu or (2) 125 

percent of the unit’s lowest seasonal 

average NOX emissions rate in a 

previous control period under the 

CSAPR NOX Ozone Season Group 1, 

Group 2, or Group 3 Trading Program, 

excluding any control periods where the 

unit operated for less than 10 percent of 

the hours in the ozone season.276

Table VII.B.8–1 shows the secondary 

emissions limitations that the proposed 

formula would have produced and 

which units would have exceeded those 

limitations if the limitations and 

formula had been in effect for the Group 

2 trading program in 2019, 2020, and 

2021 when assurance level exceedances 

occurred in Mississippi and Missouri. 

The EPA believes that in each case the 

formula functions in a reasonable 

manner, and the units identified as 

exceeding their respective secondary 

emissions limitations are sources for 

which an enforcement deterrent under 

CAA sections 113 and 304 would have 

been appropriate to compel better 

control of NOX emissions. 

TABLE VII.B.8–1—ILLUSTRATIVE RESULTS OF APPLYING PROPOSED SECONDARY EMISSIONS LIMITATION IN PREVIOUS

INSTANCES OF ASSURANCE LEVEL EXCEEDANCES

Owner/operator Unit 

Benchmark 

NOX emissions 

rate 

(lb/mmBtu) 

Actual NOX

emissions 

rate 

(lb/mmBtu) 

Secondary 

emissions 

limitation 

(tons) 

Actual NOX

emissions 

(tons) 

Exceedance 

(tons) 

Mississippi—2019 

Miss. Power ............ Watson 4 ....................... 0.137 0.176 458 524 66 

Miss. Power ............ Watson 5 ....................... 0.215 0.349 1,247 1,943 696 

Mississippi—2020 

Entergy Miss. .......... Andrus 1 ........................ 0.224 0.289 1,219 1,508 289 

Miss. Power ............ Watson 5 ....................... 0.215 0.286 1,086 1,381 295 

Missouri—2020 

Assoc. Elec. Coop. New Madrid 1 ................ 0.135 0.670 961 4,524 3,563 

Assoc. Elec. Coop. New Madrid 2 ................ 0.131 0.497 866 3,108 2,242 

Assoc. Elec. Coop. Thomas Hill 1 ................ 0.123 0.526 374 1,384 1,010 

Assoc. Elec. Coop. Thomas Hill 2 ................ 0.122 0.537 548 2,187 1,639 

Assoc. Elec. Coop. Thomas Hill 3 ................ 0.104 0.195 780 1,374 594 

Missouri—2021 

Assoc. Elec. Coop. New Madrid 1 ................ 0.135 0.652 353 1,466 1,113 

Assoc. Elec. Coop. New Madrid 2 ................ 0.131 0.611 1,054 4,700 3,646 

Assoc. Elec. Coop. Thomas Hill 1 ................ 0.123 0.146 421 440 19 

Assoc. Elec. Coop. Thomas Hill 2 ................ 0.122 0.400 600 1,801 1,201 

For further illustrations of the 

application of the proposed formula and 

secondary emissions limitation to other 

units in the states proposed to be subject 

to the expanded Group 3 trading 

program in the control periods from 

2016 through 2021, see the spreadsheet 

‘‘Illustrative Calculations Using 

Proposed Secondary Emissions 

Limitation Formula’’, available in the 

docket. The EPA notes that, with the 

exception of the units listed in Table 

VII.B.8–1, no unit shown in the 

spreadsheet as having emissions 

exceeding the illustrative secondary 

emissions limitation calculated for the 

unit would have violated the proposed 

prohibition because no violation would 

occur in the absence of an exceedance 

of the assurance level and 

apportionment of responsibility for a 

share of the exceedance to the unit 

under the assurance provisions. 

The EPA requests comment on the 

proposal to establish a secondary 

emissions limitation for the Group 3 

trading program as described in this 

section. The EPA specifically requests 

comment on the proposed form of the 

secondary emissions limitation, the 

proposed formula for computing each 

unit’s secondary emissions limitation, 

and the proposed values for the 

screening parameters used in the 

calculations. 

9. Unit-Level Allowance Allocation and 

Recordation Procedures 

In the Revised CSAPR Update, the 

EPA established default procedures for 

allocating CSAPR NOX Ozone Season 

Group 3 allowances (‘‘Group 3 

allowances’’) in amounts equal to each 

state emissions budget for each control 

period among the sources in the state for 

use in complying with the Group 3 

trading program. The EPA also provided 

states with several options to submit SIP 

revisions which, if approved, would 

result in the replacement of EPA’s 

allowance allocations with statedetermined allowance allocations for 

the 2022 control period and beyond. 

The current regulations (i.e., before this 

proposed rule) provide that EPA’s 

allocations and allocation procedures 

apply for the 2021 control period and, 

by default, for subsequent control 

periods unless and until a state provides 

state-determined allowance allocations 

under an approved SIP revision. 

The current default allocation process 

for the Group 3 trading program 

established in the Revised CSAPR 

Update involves three main steps. First, 

a portion of each state emissions budget 

for each control period is reserved for 

potential allocation to units that are 

subject to allowance holding 

requirements and that would not 

otherwise receive allowance allocations 

in the overall allocation process. Under 

the current Group 3 trading programs, 

the reserved allowances are made 

available generally (but not 

exclusively 277) to ‘‘new’’ units—which 

for purposes of the Revised CSAPR 

Update means units commencing 

commercial operation on or after 

January 1, 2019—through a ‘‘new unit 

set-aside’’ established for qualifying 

units in each state and, if areas of Indian 

country exist within the state’s borders, 

a separate ‘‘Indian country new unit setVerDate Sep<11>2014 20:07 Apr 05, 2022 Jkt 256001 PO 00000 Frm 00090 Fmt 4701 Sfmt 4702 E:\FR\FM\06APP2.SGM 06APP2

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278Under the current regulations for each of the 

CSAPR trading programs, when a unit that has 

received allocations as an ‘‘existing’’ unit ceases 

operation, after a specified number of control 

periods the unit loses the allocations, which are 

then allocated to the state’s new unit set-asides for 

subsequent control periods. 

279A unit that has received allocations as an 

‘‘existing’’ unit, then loses its allocations because of 

non-operation, and then later resumes operation is 

treated as a type of ‘‘new’’ unit for allocations 

purposes. 

280As further discussed in Section VII.B.12 of this 

proposed rule, the EPA is also proposing to make 

this revision to the regulations for the other CSAPR 

trading programs in addition to the Group 3 trading 

program. 

281For additional discussion of the ODEQ v. EPA 

decision and other issues related to the CAA 

implementation planning authority of states, tribes, 

and the EPA in various areas of Indian country, see 

Section IV.C.2 of this proposed rule. 

aside’’ for qualifying units in such 

Indian country. Second, in advance of 

each control period, the unreserved 

portion of the state budget is allocated 

among the state’s eligible ‘‘existing’’ 

units—which for purposes of the 

Revised CSAPR Update generally means 

units that commenced commercial 

operation before January 1, 2019—and 

the allocations are recorded in the 

respective sources’ compliance 

accounts. Finally, after the control 

period but before the compliance 

deadline by which sources must hold 

allowances to cover their emissions for 

the control period, allowances from the 

reserved portions of the budget are 

allocated to qualifying units, any 

remaining reserved allowances not 

allocated to qualifying units are 

allocated among the state’s existing 

units, and the allocations are recorded 

in the respective sources’ compliance 

accounts. 

In this rulemaking, the EPA would 

retain the overall three-step allocation 

process summarized above but is 

proposing revisions to each step to 

better address units in Indian country 

and to better coordinate the unit-level 

allocation process with the proposed 

dynamic budget-setting process 

discussed in Section VII.B.4 of this 

proposed rule. Like the allocation 

process established in CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update, the revised process proposed in 

this rulemaking would be designed to 

provide default allowance allocations to 

all units that are subject to allowance 

holding requirements, including, for the 

first time under any CSAPR trading 

program, an existing EGU in Indian 

country not covered by a state’s CAA 

implementation planning authority. The 

proposed revisions to the three steps are 

discussed in Sections VII.B.4.a, 

VII.B.4.b, and VII.B.4.c of this proposed 

rule, respectively. 

Echoing the approach to unit-level 

allocations followed in CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update, in this rulemaking, EPA is again 

proposing to provide states with several 

options to submit SIP revisions which, 

if approved, would result in the 

replacement of EPA’s default allocations 

with state-determined allocations for 

subsequent control periods. 

Specifically, the proposed regulations 

would provide that EPA’s allocations 

and allocation procedures will apply for 

the 2023 control period and, by default, 

for subsequent control periods unless 

and until a state provides statedetermined allocations under an 

approved SIP revision. The options to 

submit SIP revisions that would 

accomplish this purpose are discussed 

in Section VII.D of this document. 

Similarly, for a covered area of Indian 

country not subject to a state’s CAA 

implementation planning authority, a 

tribe could elect to work with the EPA 

under the Tribal Authority Rule to 

develop a full or partial tribal 

implementation plan under which the 

tribe would determine allowance 

allocations that would replace EPA’s 

default allocations for subsequent 

control periods. 

a. Set-Asides of Portions of State 

Emissions Budgets for New Units 

As the first step in the default 

allocation process that the EPA has 

applied under CSAPR, the CSAPR 

Update, and the Revised CSAPR Update 

for any control period where a state 

does not employ an alternative 

allocation process pursuant to an 

approved SIP revision, EPA has 

reserved a portion of the state’s 

emissions budget for potential 

allocation to units that are subject to 

allowance holding requirements and 

that would not otherwise receive 

allowance allocations in the overall 

allocation process. Consistent with the 

budget-setting approach in those 

rulemakings, where the state emissions 

budgets for all future control periods 

were determined in the initial 

rulemakings, the amounts of the 

reserved portions of the budgets were 

also determined in the initial 

rulemakings.278

The units for which portions of the 

budgets were reserved in set-asides have 

fallen into two main categories: First, 

units for which the data needed to 

determine allowance allocations does 

not exist at the time when the 

allocations for other units were being 

determined—i.e., ‘‘new’’ units 279—and 

second, units that would be left out if 

a state chooses to replace EPA’s default 

allocations with state-determined 

allocations—i.e., any units in Indian 

country not covered by a state’s CAA 

implementation planning authority. 

Because there were no existing units in 

what the EPA understood to be Indian 

country for purposes of CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update, potential units in Indian 

country were considered to be a 

subcategory of ‘‘new’’ units, and the two 

types of set-asides that have been 

created are ‘‘new unit set-asides’’ and 

‘‘Indian country new unit set-asides.’’ 

The principal difference between these 

two types of set-asides under the 

regulations for all of the CSAPR trading 

programs has been that a state can take 

over administration of the allowances 

allocated to a new unit set-aside from 

the EPA through an approved SIP 

revision but cannot take over 

administration of the allowances 

allocated to an Indian country new unit 

set-aside. 

In this rulemaking, the EPA is 

proposing several revisions affecting the 

establishment of set-asides. The first 

proposed revision, which is largely 

unrelated to the other aspects of this 

rulemaking, would update the 

regulations for the Group 3 trading 

program 280 to reflect the D.C. Circuit’s 

holding in ODEQ v. EPA that the 

relevant states have initial CAA 

implementation planning authority in 

non-reservation areas of Indian country 

until displaced by a demonstration of 

tribal jurisdiction over such an area.281

Consistent with this holding, EPA is 

proposing to revise language in the 

Group 3 trading program regulations 

that, for purposes of allocating 

allowances from a given state’s 

emissions budget, currently 

distinguishes between (1) the set of 

units within the state’s borders that are 

not in Indian country and (2) the set of 

units within the state’s borders that are 

in Indian country. As revised, the 

provisions would distinguish between 

(1) the set of units within the state’s 

borders that are not in Indian country or 

are in areas of Indian country covered 

by the state’s CAA implementation 

planning authority and (2) the set of 

units within the state’s borders that are 

in areas of Indian country not covered 

by the state’s CAA implementation 

planning authority. The revised 

language would more accurately 

distinguish which units are, or are not, 

covered by a state’s CAA 

implementation planning authority, 

which is the underlying purpose for 

which the term ‘‘Indian country’’ is 

currently used in the allowance 

allocation provisions. The effect of the 

proposed revision would be that any 


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282The EPA notes that the units that would be 

treated for allocation purposes in the same manner 

as units not in Indian country would include units 

in any areas of Indian country subject to a state’s 

CAA implementation planning authority, whether 

those are non-reservation areas (consistent with 

ODEQ) or reservation areas (such as areas of Indian 

country within Oklahoma’s borders covered by the 

EPA’s October 1, 2020 approval of Oklahoma’s 

request under SAFETEA, as discussed in Section 

IV.C.2 of this proposed rule). 

283 In coordination with the dynamic budgeting 

process discussed in Section VII.B.4 of this 

proposed rule, each unit included in the unit 

inventory used to determine a state’s emissions 

budget for a given control period in 2025 or a later 

year would be considered an ‘‘existing’’ unit for that 

control period for purposes of the determination of 

unit-level allowance allocations. In other words, 

there would no longer be a single fixed date that 

would divide ‘‘existing’’ from ‘‘new’’ units. 

284As noted in Section VII.D, of this proposed 

rule a tribe could elect to work with EPA under the 

Tribal Authority Rule to develop a full or partial 

tribal implementation plan under which the tribe 

would determine allowance allocations for units in 

the relevant area of Indian country that would 

replace EPA’s default allocations for subsequent 

control periods. 

285Allowances from an Indian country new unit 

set-aside that are not allocated to qualifying new 

units are first transferred to the state’s new unit setaside, and if the allowances are still not allocated 

to qualifying new units, the allowances are then 

reallocated to the state’s existing units. 

units located in areas of ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151 

that are covered by a state’s CAA 

implementation planning authority 

would be treated for allowance 

allocation purposes in the same manner 

as units in areas of the state that are not 

Indian country, consistent with the 

ODEQ holding.282

The remaining proposed revisions, 

which are interrelated, concern the 

types of set-asides that in the context of 

this proposal will best accomplish the 

goal of ensuring the availability of 

allocations to units that are subject to 

allowance holding requirements and 

that would not otherwise receive 

allowance allocations. One proposed 

revision to the types of set-asides 

addresses allocations to existing units in 

Indian country. The revised geographic 

scope of the Group 3 trading program 

under this proposal would for the first 

time include an existing EGU in Indian 

country not covered by a state’s CAA 

implementation planning authority—the 

Bonanza coal-fired unit in the Uintah 

and Ouray Reservation within Utah’s 

borders. In order to provide an option 

for Utah (or a similarly situated state in 

the future) to replace EPA’s default 

allowance allocations to most existing 

units with state-determined allocations 

through a SIP revision while continuing 

to ensure the availability of a default 

allocation to the Bonanza unit (or 

similarly situated units in the future), 

the EPA proposes to revise the Group 3 

trading program regulations to provide 

for ‘‘Indian country existing unit setasides.’’ Specifically, for each state and 

for each control period where the 

inventory of units used to compute the 

state’s emissions budget includes one or 

more existing units 283 in an area of 

Indian country not covered by the 

state’s CAA implementation planning 

authority, the EPA would reserve a 

portion of the state’s emissions budget 

in an Indian country existing unit setaside for the unit or units. The amount 

of each Indian country existing unit setaside would equal the sum of the 

default allocations that the units 

covered by the set-aside would receive 

if the allocations to all existing units 

within the state’s borders were 

computed according to EPA’s default 

allocation procedure (which is 

discussed in Section VII.B.9.b of this 

proposed rule). Immediately after 

determining the amount of a state’s 

emissions budget for a control period 

(and after reserving a portion for 

potential allocation to new units, as 

discussed below), the EPA would first 

determine the default allocations for all 

existing units within the state’s borders, 

then allocate the appropriate quantity of 

allowances to the Indian country 

existing unit set-aside, then allocate the 

allowances from the set-aside to the 

covered units in Indian country, and 

finally record the allocations in the 

sources’ compliance accounts at the 

same time as the allocations to other 

sources not in Indian country. The 

existence of the Indian country existing 

unit set-aside thus would have no 

substantive effect unless and until the 

relevant state chose to replace EPA’s 

default allowance allocations through a 

SIP revision, in which case the state 

would have the ability to establish statedetermined allocations for the units 

subject to the state’s CAA 

implementation planning authority 

while the EPA would continue to 

administer the Indian country existing 

unit set-aside for the units in Indian 

country not covered by the state’s CAA 

implementation planning authority.284

The EPA believes the proposal to 

establish Indian country existing unit 

set-asides would accomplish the 

objective of allowing states to control 

allowance allocations to units covered 

by their CAA implementation planning 

authority while providing equitable 

allocations to units in Indian country 

not covered by such authority. 

The remaining revisions to the types 

of set-asides address the set-asides used 

to ensure availability of allowance 

allocations to new units in light of the 

division of the budget for existing units 

into a reserved portion for existing units 

in Indian country and an unreserved 

portion for other existing units. Under 

the current Group 3 trading program 

regulations, allowances for new units 

are provided from separate new unit setasides and Indian country new unit setasides. The EPA proposes to combine 

these two types of set-asides starting 

with the 2023 control period by 

eliminating the Indian country new unit 

set-asides and expanding eligibility for 

allocations from the new unit set-asides 

to include units anywhere within the 

relevant states’ borders. However, as 

with the Indian country new unit setasides under the current regulations, the 

EPA would continue to administer the 

new unit set-asides in the event a state 

chose to replace EPA’s default 

allocations to existing units with statedetermined allocations, thereby 

ensuring the availability of allocations 

to any new units not covered by a state’s 

CAA implementation planning 

authority. 

The reason for the proposed revisions 

to the new unit set-asides and Indian 

country new unit set-asides is to avoid 

unnecessary and potentially inequitable 

changes to the degree to which 

individual existing units contribute to, 

or benefit from, the new unit set-asides. 

Under the current regulations, the 

allowances used to establish these setasides are reserved from each state 

emissions budget before determination 

of the allocations from the unreserved 

portion of the budget to existing units, 

so that certain existing units—generally 

those receiving the largest allocations— 

contribute to creation of the set-asides 

through roughly proportional reductions 

in their allocations. Later, if any 

allowances in a set-aside are not 

allocated to qualifying new units, the 

remaining allowances are reallocated to 

the existing units in proportion to their 

initial allocations from the unreserved 

portion of the budget, so that certain 

existing units—again, generally those 

receiving the largest allocations—benefit 

from the reallocations in rough 

proportion to their previous 

contributions.285 The EPA believes 

maintaining this symmetry, where the 

same existing units—whether in Indian 

country or not—both contribute to and 

potentially benefit from the set-asides, is 

a reasonable policy objective, and doing 

so requires that the EPA continue to 

administer the new unit set-asides in 

the event a state chooses to replace 

EPA’s default allocations to existing 

units with state-determined allocations, 

because otherwise the EPA would be 

unable to ensure that the units in Indian 

country would receive an appropriate 


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286 If units in Indian country were unable to share 

in the benefits of reallocation of allowances from 

the new unit set-asides, it would be possible to 

achieve a different form of symmetry by 

simultaneously exempting the units in Indian 

country from the obligation to share in the 

contribution of allowances to the new unit setasides. 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. 

share of any reallocated allowances.286

Since the principal difference between 

the new unit set-asides and the Indian 

country new unit set-asides under the 

current regulations is that the EPA 

continues to administer the Indian 

country new unit set-asides in the event 

a state chooses to replace EPA’s default 

allocations with state-determined 

allocations, if under the revised 

regulations the EPA would need to 

continue to administer the new unit setasides, then there would no longer be 

any reason to establish separate Indian 

country new unit set-asides. 

With respect to the total amounts of 

allowances that would be set aside for 

potential allocation to new units from 

the emissions budgets for each state, for 

the control periods in 2023 and 2024 

(but not for subsequent control periods, 

as discussed below), EPA proposes to 

establish total set-aside amounts equal 

to the projected amounts of emissions 

from any planned units in the state for 

the control period, plus an additional 

2% of the state emissions budget to 

address any unknown new units. For 

example, if planned units in a state are 

projected to emit 3% of the state’s NOX

ozone season emissions budget, then the 

new unit set-aside for the state would be 

set at 5 percent, which is the sum of the 

minimum 2% set-aside plus an 

additional 3 percent for planned units. 

This is the same approach previously 

used to establish the amounts of new 

unit set-asides in CSAPR, the CSAPR 

Update, and the Revised CSAPR Update 

for all the CSAPR trading programs. See, 

e.g., 76 FR 48292 (August 8, 2011). As 

under the Revised CSAPR Update, EPA 

proposes to make an exception for New 

York for the 2023 and 2024 control 

periods, establishing a total new unit 

set-aside amount for each control period 

of 5 percent of the state’s emissions 

budget, with no additional 

consideration for planned units, because 

this approach is consistent with New 

York’s preferences as reflected in an 

approved SIP addressing allowance 

allocations for the Group 2 trading 

program. Because the amounts of the 

state emissions budgets for the 2023 and 

2024 control periods would be 

determined in the rulemaking, the 

amounts of the new unit set-asides for 

these control periods would also be 

determined in the rulemaking. The 

proposed amounts are shown in Tables 

VII.B.9.a-1 and VII.B.9.a-2 of this 

proposed rule. 

TABLE VII.B.9.a–1—PROPOSED CSAPR NOX OZONE SEASON GROUP 3 NEW UNIT SET-ASIDE (NUSA) AMOUNTS FOR

THE 2023 CONTROL PERIOD a

State 

Emissions 

budgets 

(tons) 

New unit 

set-aside 

amount 

(percent) 

New unit 

set-aside 

amount 

(tons) 

Alabama ....................................................................................................................................... 6,364 3 191 

Arkansas ...................................................................................................................................... 8,889 2 178 

Delaware ...................................................................................................................................... 384 14 54 

Illinois ........................................................................................................................................... 7,364 5 368 

Indiana ......................................................................................................................................... 11,151 2 223 

Kentucky ...................................................................................................................................... 11,640 2 233 

Louisiana ...................................................................................................................................... 9,312 2 186 

Maryland ...................................................................................................................................... 1,187 2 24 

Michigan ....................................................................................................................................... 10,718 4 429 

Minnesota .................................................................................................................................... 3,921 2 78 

Mississippi .................................................................................................................................... 5,024 2 100 

Missouri ........................................................................................................................................ 11,857 2 237 

Nevada ......................................................................................................................................... 2,280 6 137 

New Jersey .................................................................................................................................. 799 2 16 

New York ..................................................................................................................................... 3,763 5 188 

Ohio ............................................................................................................................................. 8,369 5 418 

Oklahoma ..................................................................................................................................... 10,265 2 205 

Pennsylvania ................................................................................................................................ 8,855 3 266 

Tennessee ................................................................................................................................... 4,234 2 85 

Texas ........................................................................................................................................... 38,284 2 766 

Utah ............................................................................................................................................. 14,981 3 449 

Virginia ......................................................................................................................................... 3,090 5 155 

West Virginia ................................................................................................................................ 12,478 2 250 

Wisconsin ..................................................................................................................................... 5,963 2 119 

Wyoming ...................................................................................................................................... 9,125 3 274 

Table Notes: 

a In the event a final rule in this rulemaking becomes effective after May 1, 2023, the emissions budgets for the 2023 control period would be 

adjusted under the rule’s proposed transitional provisions to ensure the new budgets would apply only after the rule’s effective date, even though 

the revised Group 3 trading program would be implemented for most sources as of the start of the 2023 ozone season on May 1, 2023. The 

2023 budget amounts shown in Table VII.B.9.a–1 do not reflect these possible adjustments. The transitional provisions are discussed in Section 

VII.B.11 of this proposed rule. 


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20128 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

287The proposed revisions to the procedures for 

computing unit-level allowance allocations in this 

rulemaking apply only to the Group 3 trading 

TABLE VII.B.9.a–2—PROPOSED CSAPR NOX OZONE SEASON GROUP 3 NEW UNIT SET-ASIDE (NUSA) AMOUNTS FOR

THE 2024 CONTROL PERIOD

State 

Emissions 

budgets 

(tons) 

New unit 

set-aside 

amount 

(percent) 

New unit 

set-aside 

amount 

(tons) 

Alabama ....................................................................................................................................... 6,306 3 189 

Arkansas ...................................................................................................................................... 8,889 2 178 

Delaware ...................................................................................................................................... 434 14 61 

Illinois ........................................................................................................................................... 7,463 5 373 

Indiana ......................................................................................................................................... 9,391 2 188 

Kentucky ...................................................................................................................................... 11,640 2 233 

Louisiana ...................................................................................................................................... 9,312 2 186 

Maryland ...................................................................................................................................... 1,187 2 24 

Michigan ....................................................................................................................................... 10,718 4 429 

Minnesota .................................................................................................................................... 3,921 2 78 

Mississippi .................................................................................................................................... 4,400 2 88 

Missouri ........................................................................................................................................ 11,857 2 237 

Nevada ......................................................................................................................................... 2,372 6 142 

New Jersey .................................................................................................................................. 799 2 16 

New York ..................................................................................................................................... 3,763 5 188 

Ohio ............................................................................................................................................. 8,369 5 418 

Oklahoma ..................................................................................................................................... 9,573 2 191 

Pennsylvania ................................................................................................................................ 8,855 3 266 

Tennessee ................................................................................................................................... 4,234 2 85 

Texas ........................................................................................................................................... 38,284 2 766 

Utah ............................................................................................................................................. 15,146 3 454 

Virginia ......................................................................................................................................... 2,814 5 141 

West Virginia ................................................................................................................................ 12,478 2 250 

Wisconsin ..................................................................................................................................... 5,057 2 101 

Wyoming ...................................................................................................................................... 8,573 3 257 

For control periods in 2025 and later 

years, the EPA proposes to allocate a 

total of 2% of each state emissions 

budget to a new unit set-aside, with no 

additional amount for planned new 

units. The amounts of the set-asides for 

each state and control period would be 

computed when the emissions budgets 

for the control period are established, by 

May 1 of the year before the year of the 

control period. The procedure for 

determining the amounts of the setasides based on the amounts of the state 

emissions budgets would be codified in 

the Group 3 trading program regulations 

and would reflect the same percentage 

of the emissions budget for all states. 

The purpose of the proposed change 

to the procedure for establishing the 

amounts of the set-asides is to 

coordinate with the dynamic budgetsetting process that would also become 

effective as of the 2025 control period. 

As discussed in Section VII.B.4 of this 

proposed rule, under the dynamic 

budget-setting process, each state’s 

budget for each control period would be 

computed using fleet composition 

information and the total ozone season 

heat input reported by all affected units 

in the state for the latest control period 

before the budget-setting computations, 

which would be 2 years before the 

control period for which the budgets are 

being determined. (For example, 2025 

emissions budgets would be based on 

2023 fleet composition and heat input 

data.) Moreover, as discussed in Section 

VII.B.9.b of this proposed rule, all units 

whose heat input was used in the 

budget computations for a given control 

period would be eligible to receive 

allocations as ‘‘existing’’ units in that 

control period. Consequently, by the 

2025 control period, all or almost all 

units that commence commercial 

operation before issuance of a final rule 

in this rulemaking would be considered 

‘‘existing’’ units for purposes of budgetsetting and allocations, and units 

commencing commercial operation after 

issuance of a final rule generally would 

be considered ‘‘existing’’ units for all 

but their first two full control periods of 

operation (and possibly a preceding 

partial control period). Given that new 

units would not be relying on the new 

unit set-asides as a permanent source of 

allowances, as is the case for ‘‘new’’ 

units under the other CSAPR trading 

programs, the EPA believes smaller setasides would be sufficient. 

The EPA requests comment on the 

proposals to establish Indian country 

existing unit set-asides, eliminate Indian 

country new unit set-asides, and expand 

eligibility for allocations from new unit 

set-asides to include units in Indian 

country for control periods in 2023 and 

later years. In the alternative, the EPA 

requests comment on establishing 

emissions budgets (and assurance levels 

and new unit set-asides) for the Uintah 

and Ouray Reservation separate from 

the emissions budgets (and assurance 

levels, new unit set-asides, and Indian 

country new unit set-asides) established 

for the remaining lands within Utah’s 

borders, and otherwise retaining the 

structure of prior CSAPR trading 

programs’ approach to allocations to 

new units in Indian country (i.e., 

keeping the Indian country new unit 

set-asides, and not expanding eligibility 

for allocations from the new unit setasides). The EPA also requests comment 

on the proposed new unit set-aside 

amounts for the 2023 and 2024 control 

periods, the proposed procedure for 

establishing the new unit set-aside 

amounts for the control periods in 2025 

and later years, and the proposed 

procedure for establishing the Indian 

country existing unit set-aside amounts 

for the control periods in 2023 and later 

years. 

b. Allocations to Existing Units, 

Including Units That Cease Operation 

In conjunction with the new and 

revised state emissions budgets for the 

Group 3 trading program proposed in 

this rulemaking, the EPA is necessarily 

proposing new unit-level allocations of 

Group 3 allowances to existing units.287


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20129 

program. In this rulemaking, the EPA is not 

proposing changes to or reopening the methodology 

for computing the amounts of allowances allocated 

to any unit under any other CSAPR trading 

program. 

The procedure that the EPA proposes to 

employ to compute the unit-level 

allocations is very similar but not 

identical to the procedure used to 

compute unit-level allocations for units 

subject to the Group 3 trading program 

in the Revised CSAPR Update. The 

steps of the proposed procedure for 

determining allocations from each state 

emissions budget for each control 

period, are described in detail in the 

Unit-Level Allowance Allocations 

Proposed Rule TSD. The steps are 

summarized later, with changes from 

the procedure followed in the Revised 

CSAPR Update noted. 

In the first step, the EPA would 

identify the list of units eligible to 

receive allocations for the control 

period, which would be the same set of 

units whose heat input was used in 

computing the state’s emissions budget 

for the control period (except any units 

that are included in the budgets as 

‘‘new’’ units, which would receive 

allocations from the new unit set-asides 

instead). The unit inventories used to 

compute emissions budgets for the 2023 

and 2024 control periods would be 

determined in the rulemaking in the 

same manner as in the Revised CSAPR 

Update. The unit inventories used to 

compute emissions budgets and unitlevel allocations for control periods in 

2025 and later years would be 

determined in the year before the 

control period in question based on the 

latest reported emissions and 

operational data, which is an extension 

of the methodology used in the Revised 

CSAPR Update to reflect more recent 

data (for example, the unit inventories 

used to compute 2025 budgets and 

allocations would reflect reported data 

for the 2023 control period). The 

procedures for updating the unit 

inventories for 2023 and 2024 and for 

2025 and beyond are discussed in 

Section VII.B.4 of this proposed rule, 

and the criteria that the EPA has applied 

to determine whether a unit’s scheduled 

retirement is sufficiently certain to serve 

as a basis for adjusting emissions 

budgets and unit-level allocations are 

discussed in Section VI.B and in the 

Ozone Transport Policy Analysis 

Proposed Rule TSD. With regard to the 

use of the inventories from the budgetsetting procedure in setting unit-level 

allocations, in the Revised CSAPR 

Update, the inventories used to 

establish the budgets were generally 

also used to compute unit-level 

allocations, except that units that 

commenced construction after January 

1, 2019, were not treated as eligible to 

receive allocations as existing units and 

instead received allocations from the 

new unit set-asides. Under this 

rulemaking, any unit whose heat input 

is used to set a state’s emissions budget 

for a given control period would also be 

eligible to receive allocations as an 

existing unit for that control period. 

The EPA notes that this proposal to 

base the list of eligible units on the list 

of units that reported heat input in the 

control period 2 years earlier than the 

control period for which allocations are 

being determined would represent a 

revision to the current regulations 

concerning the treatment of allocations 

to retired units. Under the current 

regulations, units that cease operations 

for 2 consecutive control periods 

continue to receive allocations as 

existing units for 3 additional years (that 

is, a total of 5 years) before the 

allowances they would otherwise have 

received are reallocated to the new unit 

set-aside for the state. Under the 

proposal in this rulemaking, units that 

cease operation would receive 

allocations for only two full control 

periods of non-operation. While the 

EPA has in prior transport rulemakings 

noted a qualitative concern that ceasing 

allowance allocations prematurely 

could distort the economic incentives of 

EGUs to continue operating when 

retirement is more economical, the EPA 

believes current market conditions are 

such that a continuation of allowance 

allocations to retiring units likely has no 

more than a de minimis effect on the 

consideration of an EGU whether to 

retire or not. 

In the second step of the procedure 

for determining allocations to existing 

units, the EPA would compile a 

database containing for each eligible 

unit the unit’s historical heat input and 

total NOX emissions data for the five 

most recent ozone seasons. For each 

unit, the EPA would compute an 

average heat input value based on the 

three highest non-zero heat input values 

over the 5-year period, or as the average 

of all the non-zero values in the period 

if there are fewer than three non-zero 

values. For each unit, the EPA would 

also determine the maximum total NOX

emissions value over the 5-year period. 

These procedures are nearly identical to 

the procedures used in the Revised 

CSAPR Update, with two exceptions. 

First, instead of using only the data 

available at the time of the rulemaking, 

for each control period the EPA would 

use data from the most recent five 

control periods for which data had been 

reported. (For example, for the 2025 

control period, the EPA would use data 

for the 2019–2023 control periods.) 

Second, to simplify the data 

compilation process, the EPA would use 

only a five-year period for NOX mass 

emissions, in contrast to the 8-year 

period used in the Revised CSAPR 

Update for NOX mass emissions. 

In the third step of the procedure for 

determining allocations to existing units 

in each state, the EPA would allocate 

the available allowances for that state 

among the state’s eligible units in 

proportion to the share each unit’s 

average heat input value represents of 

the total of the average heat input values 

for all the state’s eligible units, but not 

more than the unit’s maximum total 

NOX value. If the allocations to one or 

more units are curtailed because of the 

units’ maximum total NOX values, the 

EPA would iterate the calculation 

procedure as needed to allocate the 

remaining allowances, excluding from 

each successive iteration any units 

whose allocations have already reached 

their maximum total NOX values. This 

calculation procedure is identical to the 

calculation procedure used in the 

Revised CSAPR Update (as well as the 

CSAPR Update and CSAPR). 

The unit-level allocations for the 2023 

and the 2024 control periods would be 

determined in the rulemaking based on 

the emissions budgets for those control 

periods also determined in the 

rulemaking and would be recorded 30 

days after the effective date of the final 

rule (in order to provide time to execute 

the proposed recall of 2023 and 2024 

Group 2 allowances, as discussed in 

Section VII.B.11.c of this proposed rule). 

This proposed recordation schedule 

represents a revision to the recordation 

schedule currently in the Group 3 

trading program regulations which calls 

for allocations of 2023 and 2024 Group 

3 allowances to existing units to be 

recorded on July 1, 2022. The EPA notes 

that for the three states with approved 

SIP revisions establishing their own 

methodologies for allocating Group 2 

allowances—Alabama, Indiana, and 

New York—EPA proposes to follow 

those methodologies to the extent 

possible in developing the allocations of 

Group 3 allowances for the 2023 and 

2024 control periods. For the amounts 

of the proposed allocations to existing 

units for the 2023 and 2024 control 

periods, see the ‘‘Unit-Level Allowance 

Allocations Proposed Rule TSD’’ in the 

docket. 

The unit-level allocations for each 

control period in 2025 or a later year 

would be computed immediately 

following the determination of the 

emissions budgets for the control 

period. The EPA would perform the 


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20130 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

288As discussed in Section X of this proposed 

rule, the EPA is proposing to relocate some of the 

regulatory provisions relating to administration of 

the new unit set-asides and is also proposing to 

remove certain provisions that would be made 

obsolete by proposed revisions to other provisions 

of the Group 3 trading program regulations. 

computations and issue a notice of data 

availability concerning the preliminary 

unit-level allocations for each control 

period by March 1 of the year before the 

control period. Objections to the data 

and preliminary computations could be 

submitted for 30 days, and the EPA 

would make any appropriate revisions 

and issue another notice of data 

availability by May 1 of the year before 

the control period. The EPA would then 

record the allocations by July 1 of the 

year before the control period. This 

proposed recordation schedule—which 

is necessitated by the fact that the 

amounts of the unit-level allocations to 

be recorded would not be known until 

the year before the control period, as 

just discussed—represents a revision to 

the recordation schedule currently in 

the Group 3 trading program regulations 

which calls for allocations of Group 3 

allowances to existing units for control 

periods in 2025 and later years to be 

recorded on July 1 of the third year 

before the year of the control period. 

The EPA does not propose to follow any 

state-specific methodologies as part of 

the procedures for determining default 

unit-level allocations of Group 3 

allowances for control periods in 2025 

or later years, but any state wishing to 

use a procedure different than EPA’s 

default allocations procedure could do 

so by obtaining approval of a SIP 

revision, as discussed in Section VII.D 

of this proposed rule. 

In the case of any states making statedetermined allocations under approved 

SIP revisions, the allocations would 

have to be submitted to EPA by June 1 

of the year before the control period and 

the EPA would record the allocations by 

July 1 of the year before the control 

period. The proposed submission 

deadline would represent a revision of 

the current deadline of June 1 of the 

year 3 years before the control period, 

and the proposed recordation deadline 

would represent a revision of the 

current deadline of July 1 of the year 3 

years before the control period. The 

purpose of revising the submission 

deadline is to provide each state for 

which the EPA has approved a SIP 

revision authorizing state-determined 

allowance allocations a period of time 

in which to apply the state’s preferred 

allocation methodology to the state’s 

trading budget for the appropriate 

control period. Because the state trading 

budgets under the Group 3 trading 

program as revised would not be known 

until May 1 of the year before each 

control period, states could not 

determine unit-level allocations of the 

budgets using their own methodologies 

significantly before June 1 of the year 

before the control period. Submission 

by June 1 would allow the allowance 

allocations to the units in the state to be 

recorded by July 1 of the year before the 

control period, simultaneously with the 

recordation of allocations to units in 

states where the EPA determines the 

allocations. 

As an exception to all of the 

recordation deadlines that would 

otherwise apply, the EPA proposes to 

not record any allocations of Group 3 

allowances in a source’s compliance 

account unless that source has complied 

with the requirements to surrender 

previously allocated 2023–2024 Group 2 

allowances. The surrender requirements 

are necessary to maintain the previously 

established levels of stringency of the 

Group 2 trading program for the states 

and sources that remain subject to that 

program under this final rule. The EPA 

finds that it is reasonable to condition 

the recordation of Group 3 allowances 

on compliance with the surrender 

requirements because the condition will 

spur compliance and will not impose an 

inappropriate burden on sources. The 

EPA considers establishment of this 

condition, which will facilitate the 

continued functioning of the Group 2 

trading program, to be an appropriate 

exercise of the Agency’s authority under 

CAA section 301 (42 U.S.C. 7601) to 

prescribe such regulations as are 

necessary to carry out its functions 

under the Act. 

The EPA requests comment on the 

proposed revisions to the procedures for 

allocating allowances to existing units 

under the Group 3 trading program, the 

deadlines for recording the allocations, 

and the deadlines for submission of 

state-determined allowance allocations 

to the EPA. 

c. Allocations From Portions of State 

Emissions Budgets Set Aside for New 

Units 

As promulgated in the Revised 

CSAPR Update, the Group 3 trading 

program regulations provide for the EPA 

to allocate allowances from each new 

unit set-aside and Indian country new 

unit set-aside after the end of the control 

period at issue. The regulations call for 

the EPA to allocate allowances to any 

eligible ‘‘new’’ units in the state in 

proportion to their respective emissions 

during the control period, up to the 

amounts of those emissions if the 

relevant set-aside contains sufficient 

allowances, and not exceeding those 

emissions. An eligible new unit for 

purposes of allocations from a set-aside 

for a given control period is generally 

any unit in the relevant area that 

reported emissions subject to allowance 

surrender requirements during the 

control period and that was not eligible 

to receive an allowance allocation as an 

‘‘existing’’ unit for the control period. 

Any allowances remaining in an Indian 

country new unit set-aside after the 

allocations to new units are transferred 

to the new unit set-aside for the state for 

potential allocation to new units in nonIndian country areas of the state, and 

any allowances remaining in a new unit 

set-aside after the allocations to new 

units are reallocated to the existing 

units in the state in proportion to those 

units’ previous allocations for the 

control period as existing units. The 

EPA issues a notice of data availability 

concerning the proposed allocations by 

March 1 following the control period, 

provides an opportunity for submission 

of objections, and issues a final notice 

of data availability and record the 

allocations by May 1 following the 

control period, one month before the 

June 1 compliance deadline. 

In this rulemaking, as discussed in 

Section VII.B.9.a of this document, the 

EPA is proposing to eliminate Indian 

country new unit set-asides after the 

2022 control period and to expand 

eligibility for allocations from each 

state’s new unit set-aside for a control 

period in 2023 or a later year to include 

units in Indian country within the 

state’s borders, regardless of whether the 

area of Indian country is covered by the 

state’s CAA implementation planning 

authority. The reasons for these 

proposed revisions are discussed in 

Section VII.B.9.a of this proposed rule. 

The EPA is not proposing any 

substantive revisions to the current 

Group 3 trading program provisions 

governing the procedures for allocating 

allowances from a state’s new unit setaside for a control period to the eligible 

units within the state’s borders.288

This EPA notes that the proposed 

revisions to other provisions of the 

Group 3 trading program regulations 

discussed elsewhere in this document 

will reduce the portions of the state 

emissions budgets that are allocated 

through the new unit set-asides. 

Specifically, because the new unit setasides will no longer receive any 

additional allowances when units retire, 

for control periods in 2025 and later 

years the amounts of allowances in the 

new unit set-asides will always be 2 

percent of the respective state emissions 

budgets for the respective control 

periods. This reduction in the size of the 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20131 

289The EPA is not proposing to amend the 

existing provisions of the Group 3 trading program 

regulations that govern whether units covered by 

the program must record and report required data 

on a year-round basis or may elect to record and 

Continued 

new unit set-asides is appropriate given 

that the number of consecutive control 

periods for which any particular unit is 

likely to receive allocations from a 

state’s new unit set-aside will be 

reduced to two or three before the unit 

becomes eligible to receive allocations 

from the unreserved portion of the 

state’s emissions budget. This approach 

contrasts with the approach under the 

other CSAPR trading programs where a 

new unit never becomes eligible to 

receive allocations from the unreserved 

portion of the emissions budget and 

where the new unit set-aside therefore 

needs to grow to accommodate an everincreasing share of the state’s total 

emissions. 

The EPA also notes that, as discussed 

in Sections VII.D.2 and VII.D.3 of this 

proposed rule, in the event that a state 

chooses to replace EPA’s default 

allowance allocations under the Group 

3 trading program with state-determined 

allocations through a SIP revision, the 

EPA will continue to administer the 

portion of each state emissions budget 

reserved in a new unit set-aside in order 

to ensure the availability of allowance 

allocations to new units in any areas of 

Indian country within the state not 

covered by the state’s CAA 

implementation planning authority. 

d. Incorrectly Allocated Allowances 

The Group 3 trading program 

regulations as promulgated in the 

Revised CSAPR Update include 

provisions addressing incorrectly 

allocated allowances. With regard to any 

allowances that were incorrectly 

allocated and are subsequently 

recovered, the current provisions 

generally call for the recovered 

allowances to be reallocated to other 

units in the relevant state (or Indian 

country within the borders of the state) 

through the process for allocating 

allowances from the new unit set-aside 

(or Indian country new unit set-aside) 

for the state. If the procedures for 

allocating allowances from the setasides have already been carried out for 

the control period for which the 

recovered allowances were issued, the 

allowances would be allocated through 

the set-asides for subsequent control 

periods. 

The EPA continues to view the 

current provisions for disposition of 

recovered allowances as reasonable in 

the case of any allowances that are 

recovered before the deadline for 

recording allocations of allowances from 

the new unit set-aside for the control 

period for which the recovered 

allowances were issued. However, in 

the case of any allowances that are 

recovered after that deadline, adding the 

recovered allowances to the new unit 

set-aside for a subsequent control 

period, as provided in the current 

regulations, would be inconsistent with 

the proposed trading program 

enhancements discussed elsewhere in 

this document, where the amounts of 

allowances provided in the state 

emissions budgets for each control 

period are designed to reflect the most 

current available information on fleet 

composition and utilization and where 

the quantities of banked allowances 

available for use in each control period 

are recalibrated for consistency with the 

state emissions budgets. The EPA 

therefore proposes that, starting with 

allowances allocated for the 2024 

control period, any incorrectly allocated 

allowances that are recovered after the 

deadline for allocating allowances from 

the new unit set-aside for that control 

period (i.e., May 1 of the year following 

the control period) would be transferred 

to a surrender account instead of being 

reallocated to other units in the state. 

The EPA requests comment on the 

proposed revision to the provisions for 

disposition of incorrectly allocated 

allowances that are recovered after the 

deadline for allocating allowances from 

the new unit set-asides for the control 

periods for which the recovered 

allowances were issued. 

10. Other Trading Program Provisions 

This section discusses how certain 

existing provisions of the Group 3 

trading program regulations would 

apply to sources that become subject to 

the program as a result of a final rule in 

this rulemaking as well as certain 

proposed changes to reporting 

requirements associated with the 

proposed backstop daily NOX emissions 

rates for coal-fired units. 

a. Designated Representative 

Requirements 

As noted in Section VII.B.1.a of this 

document, a core design element of all 

the CSAPR trading programs is the 

requirement that each source must have 

a designated representative who is 

authorized to represent all of the 

source’s owners and operators and is 

responsible for certifying the accuracy 

of the source’s reports to the EPA and 

overseeing the source’s Allowance 

Management System account. The 

necessary authorization of a designated 

representative is certified to the EPA in 

a certificate of representation. The EPA 

is not proposing any change to the 

Group 3 trading program’s designated 

representative provisions in this 

rulemaking. 

The existing designated representative 

provisions in the Group 3 trading 

program regulations already provide 

that EPA will interpret references to the 

Group 2 trading program in certain 

documents—including a certificate of 

representation as well as a notice of 

delegation to an agent or an application 

for a general account—as if the 

documents referenced the Group 3 

trading program instead of the Group 2 

trading program. For these reasons, 

sources that currently participate in the 

Group 2 trading program and that 

transition to the Group 3 trading 

program because of a final rule in this 

rulemaking will not need to submit any 

new forms as part of the transition, 

because previously submitted forms will 

be valid for purposes of the Group 3 

trading program. 

Designated representatives for sources 

that are newly affected under the Group 

3 trading program and that are not 

currently affected under the Group 2 

trading program would need to submit 

new or updated certificates of 

representation. If the source is also 

affected under other CSAPR trading 

programs or the Acid Rain Program, the 

source’s designated representative for 

all of the programs must be the same 

individual. The EPA will not record any 

Group 3 allowances allocated to a 

source in the source’s compliance 

account until the source has a properly 

authorized designated representative. 

b. Monitoring and Reporting 

Requirements 

The Group 3 trading program requires 

monitoring and reporting of emissions 

and heat input data in accordance with 

the provisions of 40 CFR part 75. In this 

rulemaking, the EPA is not proposing 

any change to these provisions of the 

Group 3 trading program except with 

respect to the monitor certification 

deadline for certain units. The EPA is 

also not proposing any changes to the 

monitoring requirements in 40 CFR part 

75 for units subject to such 

requirements. However, because of the 

proposed geographic expansion of the 

Group 3 trading program, certain units 

that were not previously subject to 

monitoring requirements under 40 CFR 

part 75 would become subject to such 

requirements. Also, the EPA is 

proposing certain additional 

recordkeeping and reporting 

requirements that would be met using 

some of the data that are already 

collected by the required monitoring 

systems.289


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report required data on an ozone season-only basis. 

See 40 CFR 97.1034(d)(1); see also 40 CFR 75.74(a)– 

(b). Thus, for units that are required or elect to 

report other data on a year-round basis, the 

proposed additional recordkeeping and reporting 

requirements would also apply year-round, while 

for units that are allowed and elect to report other 

data on an ozone season-only basis, the proposed 

additional requirements would also apply for the 

ozone season only. 

290For example, as noted in Section VII.B.7 of 

this proposed rule, there are currently five plants 

in the states covered by this proposal where SCRequipped coal-fired units and non-SCR-equipped 

coal-fired units exhaust to common stacks. If the 

owners and operators of these plants choose to 

report apportioned NOX mass emissions data in 

preference to installing and operating separate 

monitoring systems, the likely effect would be to 

overstate reported NOX mass emissions for the SCRequipped units and correspondingly understate 

reported NOX mass emissions for the non-SCR 

equipped units. This would make compliance with 

the proposed backstop daily NOX emissions rate 

more challenging for the SCR-equipped units. If the 

EPA does not require the owners and operators to 

install and operate separate monitoring systems for 

the individual units in a final rule in this 

rulemaking, the owners and operators would still 

have the option to do so if they believed it would 

be to their benefit. 

Under 40 CFR part 75, a unit has 

several options for monitoring and 

reporting, including the use of 

continuous emissions monitoring 

systems (CEMS), excepted monitoring 

methodologies for qualifying gas- or oilfired units that rely in part on fuel-flow 

metering in combination with CEMSbased or testing-based NOX emissions 

rate data, low-mass emissions 

monitoring for certain non-coal-fired, 

low emitting units, and alternative 

monitoring systems approved by the 

Administrator through a petition 

process. In addition, sources can submit 

petitions to the Administrator for 

alternatives to individual monitoring, 

recordkeeping, and reporting 

requirements specified in 40 CFR part 

75. Each CEMS must undergo rigorous 

initial certification testing and periodic 

quality assurance testing thereafter, 

including the use of relative accuracy 

test audits and 24-hour calibrations. In 

addition, when a monitoring system is 

not operating properly, standard 

substitute data procedures are applied 

to produce a conservative estimate of 

emissions for the period involved. 

Further, 40 CFR part 75 requires 

electronic submission of quarterly 

emissions reports to the Administrator, 

in a format prescribed by the 

Administrator. The reports would 

contain all of the data required 

concerning ozone season NOX

emissions. 

For units exhausting to common 

stacks, 40 CFR part 75 includes options 

that often allow monitoring to be 

conducted at the common stack on a 

combined basis for all the units as an 

alternative to installing separate 

monitoring systems for the individual 

units in the ductwork leading to the 

common stack. The units then keep 

records and report hourly and 

cumulative NOX mass emissions and in 

many cases heat input data on a 

combined basis for all units exhausting 

to the common stack. With respect to 

heat input data, but not NOX mass 

emissions data, most such units are also 

required to record and report hourly and 

cumulative data on an individual-unit 

basis, and where necessary they 

typically compute the necessary unitlevel hourly heat input values by 

apportioning the combined hourly heat 

input values for the common stack in 

proportion to the individual units’ 

recorded hourly output of electricity or 

steam. See generally 40 CFR 75.72. 

In this rulemaking, the proposed 

provisions governing default unit-level 

allowance allocations, backstop daily 

NOX emissions rates for certain coalfired units, and secondary emissions 

limitations for units contributing to 

assurance level exceedances would all 

require the use of unit-level reported 

data on NOX mass emissions (or unitlevel NOX emissions rates computed in 

part based on unit-level reported data 

on NOX mass emissions). To facilitate 

the implementation of these proposed 

provisions, the EPA is proposing to 

require all units covered by the Group 

3 trading program exhausting to 

common stacks to record and report 

unit-level hourly and cumulative NOX

mass emissions data starting with the 

2024 control period. To obtain the 

necessary unit-level hourly mass 

emissions values, the EPA proposes to 

allow the units to apportion hourly 

mass emissions values determined at 

the common stack in proportion to the 

individual units’ recorded hourly heat 

input. The proposed apportionment 

procedure would be very similar to the 

apportionment procedure that most 

such units already apply to compute 

reported unit-level heat input data. 

Because the additional required data 

values would be obtained through 

apportionment, implementation of the 

proposed additional recordkeeping and 

reporting requirements would 

necessitate a one-time update to the 

units’ data acquisition and handling 

systems but would not require any 

changes to the monitoring systems 

already needed to meet other 

requirements under 40 CFR part 75. In 

most cases, the EPA expects that the 

reported values computed through these 

apportionment procedures would 

reasonably approximate the values that 

could be obtained through installation 

and operation of separate monitoring 

systems for the individual units, 

because the units exhausting to the 

common stack would be expected to 

have similar NOX emissions rates. 

However, the EPA also recognizes that 

at some plants, unit-level values 

determined through apportionment 

based on electricity or steam output 

could overstate the reported NOX mass 

emissions for some units and 

correspondingly understate the reported 

NOX mass emissions for other units. 

While the EPA has not at this time 

identified any reason to expect such 

potential overstatement and 

understatement to cause the proposed 

requirements in this rule to be less 

stringent overall, the Agency requests 

comment on whether units in particular 

situations should be required to obtain 

the necessary hourly mass emissions 

values through installation and 

operation of monitoring systems at the 

individual-unit level.290

In addition, to implement the 

proposed backstop daily NOX emissions 

rates during the ozone season for certain 

coal-fired units, the EPA is proposing to 

require additional recordkeeping and 

reporting requirements for these units. 

Specifically, starting in 2024 for coalfired units with existing SCR controls 

serving generators larger than 100 MW, 

and starting in 2027 for other coal-fired 

units serving generators larger than 100 

MW (except circulating fluidized bed 

units), the units would be required to 

record and report total daily NOX

emissions and total daily heat input, 

daily average NOX emissions rate, and 

daily NOX emissions exceeding the 

applicable backstop daily NOX

emissions rates. The units would also be 

required to record and report 

cumulative NOX emissions exceeding 

the backstop daily NOX emissions rates 

for the ozone season. These data would 

be used to determine the allowance 

surrender requirements related to the 

backstop daily NOX emissions rates. As 

with the additional recordkeeping and 

reporting requirements discussed above 

for units exhausting to common stacks, 

implementation of the additional 

recordkeeping and reporting 

requirements for coal-fired units would 

necessitate a one-time update to the 

units’ data acquisition and handling 

systems but would not require any 

changes to the monitoring systems 

already needed to meet other 

requirements under 40 CFR part 75. 

In states whose sources currently 

participate in the Group 3 trading 

program, as well as states whose sources 

participate in the Group 2 trading 

program and would transition to the 


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291For units that currently report under 40 CFR 

part 75 only for annual programs and that use the 

optional low mass emissions methodology in 40 

CFR 75.19, an additional consideration could arise. 

Specifically, eligibility to use the low mass 

emissions methodology for reporting ozone season 

NOX mass emissions is restricted to units 

demonstrating that they have not exceeded or will 

not exceed a maximum of 50 tons of NOX per ozone 

season. In theory, some units that would be eligible 

to use the low mass emissions methodology for 

purposes of annual programs only might lose that 

eligibility because of the 50-ton ozone season cap 

(which does not apply to units reporting for annual 

programs only). Based on the emissions reports 

submitted for the 2018–2020 control periods under 

the Acid Rain Program and the CSAPR annual 

programs, none of the existing units that currently 

report under 40 CFR part 75 for annual programs 

only and that would be added to the Group 3 

trading program under the proposal are presently in 

this theoretical situation. 

292Table VII.B.3–1 of this proposed rule lists 22 

existing units in Delaware, Nevada, Utah, and 

Wyoming that appear to meet the Group 3 trading 

program’s general applicability criteria and that do 

not already report NOX emissions data to the EPA 

under 40 CFR part 75 pursuant to any other existing 

regulatory requirements. As noted in Section 

VII.B.3 of this proposed rule, six of the 22 listed 

units have reported that they may retire before the 

2023 ozone season, and the possibility exists that 

up to nine of the remaining listed units could 

qualify for an exemption from the Group 3 trading 

program available to certain cogeneration units. 

EPA therefore projects that the revision to the 

monitor certification deadline proposed in this 

section, and the related delay in allowance holding 

requirements from 2023 to 2024, could apply to 

between seven and 22 units, with the total 

estimated 2021 ozone season NOX emissions for all 

such units ranging between 250 and 450 tons. 

During the period before allowance holding 

requirements apply to the units—i.e., the period 

from the effective date of a final rule in this 

rulemaking until the start of the 2024 control 

period—other requirements of the program would 

still apply, such as the requirement for submission 

of a certificate of representation by a designated 

representative and the requirements related to 

installation and certification of required monitoring 

systems. 

293The EPA is not proposing to create a ‘‘safety 

valve mechanism’’ in this rulemaking analogous to 

the safety valve mechanism established under the 

Revised CSAPR Update. 

Group 3 trading program under this 

proposal, units that are not subject to 

the proposed backstop daily NOX

emissions rates would not need to make 

any changes to their current monitoring 

and reporting as a result of the 

transition. The sources in states 

currently in the Group 2 trading 

program would be required to begin 

monitoring and reporting of NOX

emissions and operational data for 

purposes of the Group 3 trading 

program as of May 1, 2023, the start of 

the 2023 control period. 

In states whose sources do not 

currently participate in the Group 2 

trading program, any sources that 

currently report ozone season NOX mass 

emissions according to 40 CFR part 75 

to comply with SIP requirements and 

that are not subject to the proposed 

backstop daily NOX emissions rates 

similarly would not need to make any 

changes to their current monitoring and 

reporting as a result of the transition. 

Other sources in these states that 

currently report SO2 and NOX emissions 

data according to 40 CFR part 75 under 

other CSAPR trading programs or the 

Acid Rain Program would not need to 

certify new monitoring systems for 

purposes of the Group 3 trading 

program but would need to update their 

monitoring plans and possibly update 

the software in their data acquisition 

and handling systems to compute 

certain additional values from the 

measurements that are already being 

recorded. All the sources in these states 

that already have monitoring systems 

certified under 40 CFR part 75 would be 

required to begin monitoring and 

reporting of NOX emissions and 

operational data for purposes of the 

Group 3 trading program as of the later 

of May 1, 2023, or the effective date of 

the final rule.291

Finally, any sources that meet the 

applicability criteria of the Group 3 

trading program and that do not 

currently report NOX emissions data to 

the EPA under 40 CFR part 75 would 

need to certify new monitoring systems 

in accordance with part 75 before they 

would be required to monitor and report 

emissions for purposes of the Group 3 

trading program. The units the EPA has 

been able to identify as potentially 

affected under this proposal that may 

need to certify new monitoring systems 

are listed in Table VII.B.3–1 (along with 

some other units that are potentially 

affected under this proposal and that 

already have certified monitoring 

systems). Because each of the listed 

units commenced commercial operation 

more than 180 days before the date 

when a final rule in this rulemaking 

would become effective, under the 

current Group 3 trading program 

regulations (i.e., without the revisions 

proposed in this section), each unit’s 

monitor certification deadline would 

generally be the effective date of the 

final rule. To ensure that the final rule 

does not impose monitor installation 

and certification requirements on these 

units before the effective date of the 

final rule, the EPA is proposing to revise 

the Group 3 trading program’s monitor 

certification deadline provisions to 

establish a 180-day window for 

certification of the new monitoring 

systems after the effective date of a final 

rule in this rulemaking for units that do 

not already have monitoring systems 

certified under 40 CFR part 75, similar 

to the 180-day window already 

provided to units commencing 

commercial operation after (or less than 

180 days before) the final rule’s effective 

date. The 180th day for units in this 

situation would likely fall after the end 

of the 2023 ozone season, with the 

result that the certification deadline 

would be extended until May 1, 2024, 

the first day of the 2024 ozone season. 

Because the program’s allowance 

holding requirements apply to a given 

unit only after that unit’s monitor 

certification deadline, the units in this 

situation consequently would become 

subject to allowance holding 

requirements as of the 2024 ozone 

season rather than the 2023 ozone 

season.292

The EPA requests comment on the 

proposed revisions to the recordkeeping 

and reporting provisions in 40 CFR part 

75 and the proposed establishment of a 

180-day window for certification of new 

monitoring systems after the effective 

date of a final rule in this rulemaking for 

units that do not already have 

monitoring systems certified under 40 

CFR part 75. As discussed above, with 

respect to units exhausting to common 

stacks, the EPA also requests comment 

on whether units in particular situations 

should be required to obtain hourly 

NOX mass emissions values through 

installation and operation of monitoring 

systems at the individual-unit level 

instead of being allowed to obtain 

values for individual units through 

apportionment of the combined values 

for the units exhausting to the common 

stack. 

11. Transitional Provisions 

This section discusses several 

provisions that the EPA proposes to 

implement in order to address the 

transition of sources into the Group 3 

trading program as revised. The 

purposes of the proposed transitional 

provisions are generally the same as the 

purposes of the analogous transitional 

provisions promulgated in the Revised 

CSAPR Update: First, accounting for the 

possibility that the effective date of a 

final rule in this rulemaking will fall 

after the starting date of the first affected 

ozone season (which in this case is, May 

1, 2023); second, establishing an 

appropriately-sized initial allowance 

bank through the conversion of 

previously banked allowances; and 

third, preserving the intended 

stringency of the Group 2 trading 

program for the sources that will 

continue to be subject to that 

program.293 However, the sources that 

would be participants in the revised 

Group 3 trading program under this 

proposal are transitioning from several 

different starting points—with some 

sources already in the Group 3 trading 


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294As discussed in Sections VII.B.7 and VII.B.8 

of this proposed rule, the proposed revisions 

establishing unit-specific backstop daily emissions 

rates and, for units contributing to assurance level 

exceedances, secondary unit-specific emissions 

limitations, would not take effect until the 2024 

control period or later. 

295The EPA notes that transitional provisions 

similar to the prorating provisions proposed in this 

section were finalized and implemented under the 

Revised CSAPR Update. 

program under its current regulations, 

some sources coming from the Group 2 

trading program, and some sources not 

currently participating in any seasonal 

NOX trading program. EPA is therefore 

proposing transitional provisions that 

differ across the sets of potentially 

affected sources based on the sources’ 

different starting points. 

a. Prorating Emissions Budgets, 

Assurance Levels, and Unit-Level 

Allowance Allocations in the Event of 

an Effective Date After May 1, 2023 

While it is EPA’s intent for a final rule 

in this rulemaking to take effect before 

the start of the Group 3 trading 

program’s 2023 control period on May 

1, 2023, it is possible that the final rule’s 

effective date will fall after that date. 

The EPA proposes to address this 

contingency by determining the 

amounts of emissions budgets and unitlevel allowance allocations on a fullseason basis in the rulemaking and by 

also including provisions in the revised 

regulations to prorate the full-season 

amounts as needed to ensure that no 

sources become subject to new or more 

stringent regulatory requirements before 

the final rule’s effective date.294

Variability limits and assurance levels 

for 2023 would be computed using the 

appropriately prorated emissions 

budgets amounts, and unit-level 

allocations would also be prorated.295

As discussed in Section VII.B.2 of this 

proposed rule, in the case of states (and 

Indian country within the states’ 

borders) whose sources do not currently 

participate in either the Group 2 trading 

program or the Group 3 trading 

program—Delaware, Minnesota, 

Nevada, Utah, and Wyoming—the 

sources would begin participating in the 

Group 3 trading program on the later of 

May 1, 2023, or the final rule’s effective 

date. For these states, in the rulemaking 

the EPA would compute the full-season 

emissions budgets that would apply for 

the entire 2023 control period if the 

final rule becomes effective no later 

than May 1, 2023, and is therefore in 

effect for the entire 153-day control 

period from May 1, 2023, through 

September 30, 2023. If the final rule 

becomes effective after May 1, 2023, the 

EPA would determine prorated 

emissions budgets by multiplying each 

full-season emissions budget by the 

number of days from the rule’s effective 

date through September 30, 2023, 

dividing by 153 days, and rounding to 

the nearest allowance. The prorated 

variability limits would be computed as 

21 percent of the prorated emissions 

budgets, rounded to the nearest 

allowance, yielding prorated assurance 

levels that equal 121 percent of the 

prorated emissions budgets. To 

determine unit-level allocation amounts 

from the prorated emissions budgets, 

the EPA would determine full-season 

allocation amounts in the rulemaking 

and would determine preliminary 

prorated allocation amounts in the same 

manner as described for the emissions 

budgets previously. The preliminary 

prorated amounts of the largest unitlevel allowance allocations for each 

state would then each be adjusted up or 

down by one allowance as needed to 

cause the sum of the final prorated unitlevel allowance allocations for the state 

to equal the state’s prorated emissions 

budget. All calculations required to 

determine the prorated emissions 

budgets and variability limits and the 

unit-level allocations for the 2023 

control period would be carried out as 

soon as possible after the EPA learns the 

effective date of a final rule in this 

rulemaking (which is expected to be 

approximately 60 days after the date of 

the final rule’s publication in the 

Federal Register). The unit-level 

allocations for both the 2023 and 2024 

control periods would be recorded in 

facilities’ compliance accounts 

approximately 30 days after the final 

rule’s effective date, as discussed in 

Section VII.B.9.b of this proposed rule. 

In the case of states (and Indian 

country within the states’ borders) 

whose sources currently participate in 

the Group 3 trading program—Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, New Jersey, New 

York, Ohio, Pennsylvania, Virginia, and 

West Virginia—the sources would 

continue to participate in the Group 3 

trading program for the 2023 control 

period, subject to prorating procedures 

designed to ensure that the changes in 

2023 emissions budgets and assurance 

levels would not substantively affect the 

sources’ requirements prior to the rule’s 

effective date. For these states, in the 

rulemaking the EPA would compute the 

full-season emissions budgets that 

would apply for the entire 2023 control 

period if the final rule becomes effective 

no later than May 1, 2023, but the EPA 

would not remove from the regulations 

the full-season emissions budgets for the 

2023 control period that were 

established in the Revised CSAPR 

Update rulemaking. Instead, the EPA 

would include both sets of emissions 

budgets and variability limits in the 

regulations, along with a provision 

indicating that the emissions budgets 

promulgated in the Revised CSAPR 

Update would apply on a prorated basis 

for the portion of the 2023 control 

period before the final rule’s effective 

date and the emissions budgets 

established in this rulemaking would 

apply on a prorated basis for the portion 

of the 2023 control period on and after 

the final rule’s effective date. Under this 

provision, the EPA would determine a 

blended emissions budget for each state 

for the 2023 control period, computed 

as the sum of the appropriately prorated 

amounts of the state’s current and 

revised emissions budgets. (For 

example, if the final rule became 

effective on the eleventh day of the 153- 

day 2023 control period, the blended 

emissions budget would equal the sum 

of 10/153 times the current emissions 

budget plus 143/153 times the revised 

emissions budget, rounded to the 

nearest allowance.) Blended variability 

limits for the 2023 control period would 

be computed as 21% of the blended 

emissions budgets, yielding blended 

assurance levels equal to 121 percent of 

the blended emissions budgets. Unitlevel allocations would be determined 

by applying the allocation procedure 

described in Section VII.B.9 of this 

proposed rule to the blended budgets. In 

the case of states (and Indian country 

within the states’ borders) whose 

sources currently participate in the 

Group 2 trading program—Alabama, 

Arkansas, Mississippi, Missouri, 

Oklahoma, Tennessee, Texas, and 

Wisconsin—the sources would begin to 

participate in the Group 3 trading 

program as of May 1, 2023, regardless of 

the final rule’s effective date, as 

discussed in Section VII.B.2 of this 

proposed rule, subject to prorating 

procedures designed to ensure that the 

transition from the Group 2 trading 

program to the Group 3 trading program 

would not substantively affect the 

sources’ requirements prior to the rule’s 

effective date. The prorating procedures 

for these states would mirror the 

procedures for the states currently in the 

Group 3 trading program, except that 

because no emissions budgets currently 

appear in the Group 3 trading program 

regulations for the states that are 

currently covered by the Group 2 

trading program, the EPA would add 

two sets of emissions budgets for these 

states to the Group 3 trading program 

regulations: First, the states’ emissions 

budgets for the 2023 control period that 

currently appear in the Group 2 trading 


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program regulations, which would be 

included in the revised Group 3 trading 

program regulations to represent the 

states’ emissions budgets for the portion 

of the 2023 control period before the 

final rule’s effective date, and second, 

the emissions budgets for the 2023 

control period established for the states 

in this rulemaking, which would be 

included in the revised Group 3 trading 

program regulations to represent the 

state’s emissions budgets for the portion 

of the 2023 control period on and after 

the final rule’s effective date. The 

procedures for determining blended 

emissions budgets, variability limits and 

assurance levels, and unit-level 

allowance allocations would be the 

same as for the states currently in the 

Group 3 trading program. Again, all 

calculations required to determine the 

prorated emissions budgets and 

variability limits and the unit-level 

allocations for the 2023 control period 

would be carried out as soon as possible 

after the EPA learns the effective date of 

a final rule in this rulemaking (which is 

expected to be approximately 60 days 

after the date of the final rule’s 

publication in the Federal Register). 

The unit-level allocations for both the 

2023 and 2024 control periods would be 

recorded in facilities’ compliance 

accounts approximately 30 days after 

the final rule’s effective date, as 

discussed in Section VII.B.9.b of this 

proposed rule. 

The reason for proposing that sources 

currently in the Group 2 trading 

program would begin to participate in 

the Group 3 trading program on May 1, 

2023 even if the final rule’s effective 

date is after May 1, 2023, is that it 

would serve the public interest and 

greatly aid in administrative efficiency 

for most elements of the Group 3 trading 

program—specifically, all elements of 

the trading program other than the 

elements designed to establish more 

stringent emissions limitations for the 

sources coming from the Group 2 

trading program—to apply to the 

sources starting on May 1, 2023. This 

would facilitate implementation of the 

Group 3 trading program in an orderly 

manner for the entire 2023 ozone season 

and reduce compliance burdens and 

potential confusion. Each of the CSAPR 

trading programs for ozone season NOX

is designed to be implemented over an 

entire ozone season. Implementing the 

transition from the Group 2 trading 

program to the Group 3 trading program 

in a manner that required the covered 

sources to participate in the Group 2 

trading program for part of the 2023 

ozone season and the Group 3 trading 

program for the remainder of that ozone 

season would be complex and 

burdensome for sources. Attempting to 

address the issue by splitting the Group 

2 and Group 3 requirements for these 

sources into separate years is not a 

viable approach, because EPA has no 

legal basis for releasing the transitioning 

Group 2 sources from the emissions 

reduction requirements found to be 

necessary in the CSAPR Update for a 

portion of the 2023 ozone season, and 

EPA similarly has no legal basis for 

deferring implementation of the 2023 

emissions reduction requirements found 

to be necessary under this rule for the 

transitioning Group 2 sources until 

2024. Moreover, the requirements of the 

current Group 2 trading program and 

the revised Group 3 trading program for 

the 2023 control period are 

substantively identical as to almost all 

provisions, such that with respect to 

those provisions, a source will not need 

to alter its operations in any manner or 

face different compliance obligations as 

a consequence of a transition from the 

Group 2 trading program to the Group 

3 trading program. Thus, the EPA 

believes that no substantive concerns 

regarding retroactivity arise from 

transitioning the sources currently in 

the Group 2 trading program to the 

Group 3 trading program starting on 

May 1, 2023, as long as those aspects of 

the revised Group 3 trading program for 

the 2023 control period that do 

meaningfully differ from the analogous 

aspects of the Group 2 trading 

program—that is, the relative 

stringencies of the two trading 

programs, as reflected in the emissions 

budgets and associated assurance 

levels—are applied only as of the 

effective date of the final rule. 

In all respects other than prorating the 

emissions budgets, variability limits and 

assurance levels, and unit-level 

allowance allocations, with respect to 

the sources currently participating in 

the Group 2 trading program or the 

Group 3 trading program, the EPA 

proposes to implement the revised 

Group 3 trading program for the 2023 

control period in a uniform manner for 

the entire control period. Thus, 

emissions would be monitored and 

reported for the entire 2023 ozone 

season (i.e., May 1, 2023, through 

September 30, 2023), and as of the 

allowance transfer deadline for the 2023 

control period (i.e., June 1, 2024) each 

source would be required to hold in its 

compliance account vintage-year 2023 

Group 3 allowances not less than the 

source’s emissions of NOX during the 

entire 2023 ozone season. Any efforts 

undertaken by one of these sources to 

reduce its emissions during the portion 

of the 2023 ozone season before the 

effective date of the rule would aid the 

source’s compliance by reducing the 

amount of Group 3 allowances that the 

source would need to hold in its 

compliance account as of the allowance 

transfer deadline, increasing the range 

of options available to the source for 

meeting its compliance obligations 

under the revised Group 3 trading 

program. In the case of the sources that 

do not currently participate in the 

Group 2 trading program or the Group 

3 trading program, the EPA similarly 

proposes to implement the revised 

Group 3 trading program for the 2023 

control period in a uniform manner for 

the entire control period, except that the 

2023 control period for these sources 

may be shorter than the normal 153-day 

length. 

The EPA requests comment on this 

approach for implementing the Group 3 

trading program in a manner that would 

apply the substantive increases in 

stringency of the emissions budgets and 

assurance levels established under the 

final rule on and after, but not before, 

the final rule’s effective date. 

b. Creation of Additional Group 3 

Allowance Bank for 2023 Control Period 

In the CSAPR Update, where the EPA 

established the Group 2 trading program 

and transitioned over 95% of the 

sources that had been participating in 

what is now the CSAPR NOX Ozone 

Season Group 1 Trading Program (the 

‘‘Group 1 trading program’’) to the new 

program, the EPA determined that it 

was reasonable to establish an initial 

bank of allowances for the Group 2 

trading program by converting almost 

all allowances banked under the Group 

1 trading program at a conversion ratio 

determined by a formula. In the Revised 

CSAPR Update, where EPA established 

the Group 3 trading program and 

transitioned approximately 55% of the 

sources that had been participating in 

the Group 2 trading program to the new 

program, the EPA similarly determined 

that it was reasonable to establish an 

initial bank of allowances for the Group 

3 trading program by converting 

allowances banked under the Group 2 

trading program at a conversion ratio 

determined by a formula, using a 

conversion procedure that was modified 

to leave much of the Group 2 allowance 

bank available for use by the 

approximately 45% of sources then in 

the Group 2 trading program that would 

remain in that program. Any conversion 

of banked allowances from a previous 

trading program for use in a new trading 

program must ensure that 

implementation of the new trading 

program will result in NOX emissions 


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296 If the proposed expansion of geographic scope 

for the Group 3 trading program is unchanged in the 

final rule, the states whose sources would continue 

to participate in the Group 2 trading program would 

be Iowa and Kansas. 

297Similar to the approach taken in the Revised 

CSAPR Update, because emissions reductions from 

some of the emissions controls that EPA has 

identified as appropriate to use in setting budgets 

are first reflected in the 2024 state budgets rather 

than the 2023 state budgets, the EPA is proposing 

to base the bank target amount on the sum of the 

states’ 2024 variability limits rather than the 2023 

variability limits. 

298By comparison, the analogous conversion ratio 

under the Revised CSAPR Update was 8-to-1. 

299 18,517 × (153¥10) ÷ 153 = 17,307. 

reductions sufficient to address 

significant contribution by all states that 

would be participating in the new 

trading program, while also providing 

industry certainty (and obtaining an 

environmental benefit) through 

continued recognition of the value of 

saving allowances through early 

reductions in emissions. EPA’s 

approach to balancing these concerns in 

the CSAPR Update through the 

conversion of banked allowances from 

the Group 1 trading program to the 

Group 2 trading program was upheld in 

Wisconsin v. EPA, see 938 F.3d at 321. 

In the current rulemaking, applying 

the same balancing principle as in the 

CSAPR Update and the Revised CSAPR 

Update, the EPA proposes to carry out 

a further conversion of allowances 

banked for control periods before 2023 

under the Group 2 trading program into 

allowances usable in the Group 3 

trading program in control periods in 

2023 and later years. Because the EPA 

is proposing to transition over 90% of 

the remaining sources in the Group 2 

trading program to the Group 3 trading 

program—much closer to the situation 

in the CSAPR Update than the situation 

in the Revised CSAPR Update—in this 

rulemaking EPA proposes to apply a 

conversion procedure similar to the 

procedure followed in the CSAPR 

Update. Under the proposed conversion 

procedure, in the final rule in this 

rulemaking the EPA would not set a 

predetermined conversion ratio but 

instead would set provisions defining 

the types of accounts whose holdings of 

Group 2 allowances would be converted 

to Group 3 allowances and establishing 

the target amount of new Group 3 

allowances that would be created. The 

proposed conversion date would be 

August 1, 2023, which is 2 months after 

the compliance deadline for the 2022 

control period under the Group 2 

trading program and ten months before 

the compliance deadline for the 2023 

control period under the Group 3 

trading program. The actual conversion 

ratio would be determined as of the 

conversion date and would be the ratio 

of the total amount of Group 2 

allowances held in the identified types 

of accounts prior to the conversion to 

the total amount of Group 3 allowances 

being created. Consistent with the 

approach taken in the CSAPR Update, 

the EPA proposes to define the types of 

accounts included in the conversion to 

include all accounts except the facility 

accounts of sources in states that would 

remain in the Group 2 trading 

program.296 Thus, the accounts whose 

holdings of Group 2 allowances would 

be converted to Group 3 allowances 

would include (1) the facility accounts 

of all sources in the states transitioning 

from the Group 2 trading program to the 

Group 3 trading program, (2) the facility 

accounts of all sources in the states 

already participating in the Group 3 

trading program, (3) the facility 

accounts of all sources in any other 

states not covered by the Group 2 

trading program that happen to hold 

Group 2 allowances as of the conversion 

date, and (4) all general accounts (that 

is, accounts that are not facility 

accounts, including other accounts 

controlled by source owners as well as 

accounts controlled by non-source 

entities such as allowance brokers). 

Creating the new Group 3 allowances 

through conversion of previously 

banked Group 2 allowances would also 

help preserve the stringency of the 

Group 2 trading program for the states 

that remain covered by that trading 

program at levels consistent with the 

stringency found to be appropriate to 

address those states’ good neighbor 

obligations with respect to the 2008 

ozone NAAQS in the CSAPR Update. 

With respect to setting the target 

amount of Group 3 allowances that 

would be created in the conversion 

process, the EPA proposes to follow the 

same approach that was used in the 

Revised CSAPR Update for creation of 

the initial Group 3 allowance bank. 

Specifically, the target amount of Group 

3 allowances to be created would be 

computed as the sum of the variability 

limits for the 2024 control period 297

established in the final rule for the 

states being transitioned to the Group 3 

trading program from the Group 2 

trading program, prorated to reflect the 

portion of the 2023 control period 

occurring on and after the effective date 

of the final rule. Based on the amounts 

of the proposed state emissions budgets 

and variability limits, the full-season 

target amount for the conversion would 

be 18,517 Group 3 allowances. The 

quantity of banked Group 2 allowances 

currently held in accounts other than 

the facility accounts of sources in Iowa 

and Kansas exceeding the quantity of 

allowances likely to be needed for 2021 

compliance is approximately 110,000 

allowances. If the quantities of banked 

Group 2 allowances did not change 

between now and the conversion date, 

and if there was no prorating 

adjustment, the conversion ratio would 

be approximately 5.9-to-1, meaning that 

one Group 3 allowance would be 

created for every 5.9 Group 2 

allowances deducted in the conversion 

process.298

As noted in Section VII.B.11.a of this 

proposed rule, it is possible that the 

effective date of this rule will occur after 

the start of the 2023 ozone season, and 

provisions are being proposed to ensure 

that the increased stringency of this 

rule’s state budgets and state assurance 

levels (i.e., the sums of the budgets and 

variability limits) would take effect only 

after the rule’s effective date. Consistent 

with these other procedures, the EPA is 

proposing to similarly prorate the bank 

target amount used in the conversion 

process. For example, if the effective 

date of the final rule is the eleventh day 

of the 153-day 2023 ozone season, the 

full-season initial bank target amount of 

18,517 allowances would be prorated to 

an initial bank target amount of 17,307 

allowances.299 The EPA notes that 

prorating the bank amount in this 

manner would not reduce sources’ 

compliance flexibility for the 2023 

ozone season, because the amounts of 

Group 3 allowances that sources would 

receive for the portion of the 2023 ozone 

season before the rule’s effective date 

would be based on the current trading 

program budgets for the 2023 control 

period before this rulemaking. The 

current trading program budgets exceed 

the sources’ collective 2021 emissions 

by approximately 18,600 tons, 

indicating potentially surplus 

allowances roughly equal to the fullseason bank conversion target amount of 

18,517 allowances. Thus, although the 

prorating procedure would reduce the 

amount of Group 3 allowances that 

would be available to sources in the 

form of an initial bank, the reduction in 

the quantity of these allowances would 

be offset by the quantities of Group 3 

allowances that would be allocated in 

excess of sources’ recent historical 

emissions levels for the portion of the 

ozone season before the final rule’s 

effective date. 

As in the CSAPR Update and the 

Revised CSAPR Update, EPA’s overall 

objective in establishing the target 

amount for the allowance conversion 

would be to achieve a total target 

amount for the bank at a level high 

enough to accommodate year-to-year 


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variability in operations and emissions, 

as reflected in states’ variability limits, 

but not high enough to allow sources 

collectively to plan to emit in excess of 

the collective state budgets. EPA 

believes that a well-established trading 

program would be able to function with 

an allowance bank lower than the full 

amount of the covered states’ variability 

limits, as discussed in section VII.B.6 

with respect to the proposed bank 

recalibration process that would begin 

with the 2024 control period. However, 

EPA also believes there are several 

compelling reasons in this instance to 

use a bank target higher than the 

minimum practicable level. 

First, making an allowance bank 

available for use in the 2023 control 

period that is somewhat higher than the 

minimum practicable level would help 

to address concerns that might 

otherwise arise regarding the transition 

to a new set of compliance 

requirements, for some sources, and the 

transition to compliance requirements 

based on revised emissions budgets 

different from the emissions budgets 

that the sources had reason to anticipate 

under previous rulemakings, for the 

remaining sources. Although the EPA is 

confident that the emissions budgets 

being proposed in this rulemaking for 

the 2023 control period are readily 

achievable, the EPA also believes that 

the existence of a somewhat larger 

allowance bank at this transition point 

will promote sources’ confidence in 

their ability to meet their 2023 

compliance obligations in general and 

in a liquid allowance market in 

particular. Second, because the large 

majority of the remaining Group 2 

allowances that would be converted to 

Group 3 allowances in this rulemaking 

are held by the sources currently in the 

Group 2 trading program, while the 

large majority of the initial bank of 

Group 3 allowances previously created 

in the conversion under the Revised 

CSAPR Update are held by the sources 

already in the Group 3 trading program, 

basing the conversion in this 

rulemaking on a target bank amount set 

in the same manner as the target bank 

amount used in the Revised CSAPR 

Update is expected to result in a less 

concentrated distribution of holdings of 

banked Group 3 allowances following 

the conversion than would be the case 

if a more stringent target bank amount 

were used under this rulemaking than 

was used in the Revised CSAPR Update. 

A lower concentration of holdings of 

banked Group 3 allowances would 

generally be expected to help ensure 

allowance market liquidity. Third, EPA 

considers it equitable to treat the 

sources in the states transitioning from 

the Group 2 trading program to the 

Group 3 trading program in this 

rulemaking roughly similarly to the 

sources in the states that transitioned 

between the same two trading programs 

in the Revised CSAPR Update with 

respect to the benefit they would receive 

under the Group 3 trading program for 

any efforts they may have made to make 

emissions reductions under the Group 2 

trading program beyond the minimum 

efforts that were required to comply 

with the emissions budgets under that 

program. Finally, to the extent that the 

proposed conversion results in a larger 

bank of allowances remaining after the 

2023 control period than is considered 

necessary to sustain a well-functioning 

trading program in subsequent control 

periods, the excess would be removed 

from the program in the proposed bank 

recalibration process that would be 

implemented starting with the 2024 

control period and therefore would not 

weaken sources’ incentives to control 

emissions on a permanent basis. 

The EPA requests comment on the 

proposal to create additional banked 

Group 3 allowances through the 

conversion of Group 2 allowances 

banked for control periods before 2023. 

c. Recall of Group 2 Allowances 

Allocated for Control Periods After 2022 

To maintain the previously 

established levels of stringency of the 

Group 2 trading program for the states 

and sources that remain subject to that 

program under this proposed rule, the 

EPA proposes to recall CSAPR NOX

Ozone Season Group 2 allowances 

equivalent in amount and usability to 

all vintage year 2023–2024 CSAPR NOX

Ozone Season Group 2 allowances 

previously allocated to sources in Group 

3 states and areas of Indian country and 

recorded in the sources’ compliance 

accounts. The proposed recall 

provisions would apply to all sources in 

jurisdictions newly added to the Group 

3 trading program in whose compliance 

accounts CSAPR NOX Ozone Season 

Group 2 allowances for a control period 

in 2023 or 2024 were recorded, 

including sources where some or all 

units have permanently retired or where 

the previously recorded 2023–2024 

allowances have been transferred out of 

the compliance account. The proposed 

recall provisions provide a flexible 

compliance schedule intended to 

accommodate any sources that have 

already transferred the previously 

recorded 2023–2024 allowances out of 

their compliance accounts and allows 

Group 2 allowances of earlier vintages 

to be surrendered to achieve 

compliance. Like the similar recall 

provisions finalized in the Revised 

CSAPR Update, the proposed recall 

provisions include specifications for 

how the recall provisions apply in 

instances where a source and its 

allowances have been transferred to 

different parties and for the procedures 

that the EPA will follow to implement 

the recall. 

Under the Group 2 trading program 

regulations, each Group 2 allowance is 

a ‘‘limited authorization to emit one ton 

of NOX during the control period in one 

year,’’ where the relevant limitations 

include the EPA Administrator’s 

authority ‘‘to terminate or limit the use 

and duration of such authorization to 

the extent the Administrator determines 

is necessary or appropriate to 

implement any provision of the Clean 

Air Act.’’ 40 CFR 97.806(c)(6)(ii). The 

Administrator proposes to determine 

that, in order to effectively implement 

the Group 2 trading program as a 

compliance mechanism through which 

states not subject to the Group 3 trading 

program may continue to meet their 

obligations under CAA section 

110(a)(2)(D)(i)(I) with regard to the 2008 

ozone NAAQS, it is necessary to limit 

the use of Group 2 allowances 

equivalent in quantity and usability to 

all Group 2 allowances previously 

allocated for the 2023–2024 control 

periods and recorded in the compliance 

accounts of sources in the newly added 

Group 3 jurisdictions. The Group 2 

allowances that have already been 

allocated to sources in the newly added 

Group 3 states for the 2023–2024 control 

periods and recorded in the sources’ 

compliance accounts represent the 

substantial majority of the total 

remaining quantity of Group 2 

allowances that have been allocated and 

recorded for the 2023–2024 control 

periods and that were not already made 

subject to recall when other 

jurisdictions were transferred from the 

Group 2 trading program to the Group 

3 trading program in the Revised CSAPR 

Update. Because allowances can be 

freely traded, if the use of the 2023– 

2024 Group 2 allowances previously 

recorded in newly added Group 3 

sources’ compliance accounts (or 

equivalent Group 2 allowances) were 

not limited, the effect would be the 

same as if the EPA had issued to sources 

in the states that will remain covered by 

the Group 2 trading program a quantity 

of allowances available for compliance 

under the 2023–2024 control periods 

many times the levels that the EPA 

determined to be appropriate emissions 

budgets for these states in the CSAPR 

Update. Through the use of banked 

allowances, the excess Group 2 


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300The EPA is currently unaware of any source 

that would need to use this flexibility but has 

included the option in the proposal to address the 

theoretical possibility of such a situation. 

301The first control period for the Group 2 trading 

program was in 2017. 302As discussed later in this section and in 

Section VII.B.9.b, the EPA is proposing to condition 

recordation of any allocations of Group 3 

allowances in a source’s compliance account on the 

source’s prior compliance with the proposed recall 

requirements for Group 2 allowances. The purpose 

of providing a first deadline for the recall 

provisions 15 days after a final rule’s effective 

would be to ensure that sources have an early 

opportunity to comply with the recall provisions in 

order to be eligible to have allocations of Group 3 

allowances recorded in their accounts as proposed 

30 days after the final rule’s effective date. Because 

the vast majority of sources subject to the proposed 

recall provisions already hold sufficient Group 2 

allowances to comply with the recall provisions, 

the EPA anticipates that the sources would easily 

be able to comply with the proposed first recall 

deadline. 

allowances would affect compliance 

under the Group 2 trading program in 

control periods after 2024 as well. 

Continued implementation of the Group 

2 trading program at levels of stringency 

consistent with the levels contemplated 

under the CSAPR Update therefore 

requires that the EPA limit the use of 

the excess allowances, as the EPA is 

proposing here. 

In this rulemaking, the EPA proposes 

to implement limitations on the use of 

the excess 2023–2024 Group 2 

allowances through requirements to 

surrender, for each 2023–2024 Group 2 

allowance recorded in a newly added 

Group 3 source’s compliance account, 

one Group 2 allowance of equivalent 

usability under the Group 2 trading 

program. The surrender requirements 

would apply to the owners and 

operators of the Group 3 sources in 

whose compliance account the excess 

2023–2024 Group 2 allowances were 

initially recorded. In general, each 

source’s current owners and operators 

would be required to comply with the 

surrender requirements for the source 

by ensuring that sufficient allowances to 

complete the deductions are available in 

the source’s compliance account by one 

of two possible deadlines discussed 

below. However, an exception would be 

provided if a source’s current owners 

and operators obtained ownership and 

operational control of the source in a 

transaction that did not include rights to 

direct the use and transfer of some or all 

of the 2023–2024 Group 2 allowances 

allocated and recorded (either before or 

after that transaction) in the source’s 

compliance account. The proposed rule 

provides that in such a circumstance, 

with respect to the 2023–2024 Group 2 

allowances for which rights were not 

included in the transaction, the 

surrender requirements would apply to 

the most recent former owners and 

operators of the source before any such 

transactions occurred. Because in this 

situation a source’s former owners and 

operators might lack the ability to access 

the source’s compliance account for 

purposes of complying with the 

surrender requirements, the former 

owners and operators would instead be 

allowed to meet the surrender 

requirements with Group 2 allowances 

held in a general account.300

To provide as much flexibility as 

possible consistent with the need to 

limit the use of the excess Group 2 

allowances, for each 2023–2024 Group 2 

allowance recorded in a Group 3 

source’s compliance account, the EPA 

proposes to accept the surrender of 

either the same specific 2023–2024 

Group 2 allowance or any other Group 

2 allowance with equivalent (or greater) 

usability under the Group 2 trading 

program. Thus, a surrender requirement 

with regard to a Group 2 allowance 

allocated for the 2023 control period 

could be met through the surrender of 

any Group 2 allowance allocated for the 

2023 control period or the control 

period in any earlier year—in other 

words, any 2017–2023 Group 2 

allowance.301 Similarly, the surrender 

requirement with regard to a 2024 

Group 2 allowance could be met 

through the surrender of any 2017–2024 

Group 2 allowance. 

Owners and operators subject to the 

surrender requirements could choose 

from two possible deadlines for meeting 

the requirements. The first deadline 

would be 15 days after the effective date 

of a final rule in this rulemaking.302 As 

soon as practicable or after this date, the 

EPA would make a first attempt to 

complete the deductions of Group 2 

allowances required for each Group 3 

source from the source’s compliance 

account. The EPA would deduct Group 

2 allowances first to address any 

surrender requirements for the 2023 

control period and then to address any 

surrender requirements for the 2024 

control period. When deducting Group 

2 allowances to address the surrender 

requirements for each control period, 

EPA would first deduct allowances 

allocated for that control period and 

then would deduct allowances allocated 

for each successively earlier control 

period. This order of deductions is 

intended to ensure that whatever Group 

2 allowances are available in the 

account are applied to the surrender 

requirements in a manner that both 

maximizes the extent to which all of the 

source’s surrender requirements would 

be met and also ensures that any Group 

2 allowances left in the source’s 

compliance account after completion of 

all required deductions would be the 

earliest allocated, and therefore most 

useful, Group 2 allowances possible. 

Among the Group 2 allowances 

allocated for a given control period, The 

EPA would first deduct allowances that 

were initially recorded in that account, 

in the order of recordation, and would 

then deduct allowances that were 

transferred into that account after 

having been initially recorded in some 

other account, in the order of 

recordation. 

Following the first attempt to deduct 

Group 2 allowances to address Group 3 

sources’ surrender requirements, the 

EPA would send a notification to the 

designated representative for each such 

source (as well as any alternate 

designated representative) indicating 

whether all required deductions were 

completed and, if not, the additional 

amounts of Group 2 allowances usable 

in the 2023 or 2024 control periods that 

must be held in the appropriate account 

by the second surrender deadline of 

September 15, 2023. Each notification 

would be sent to the email addresses 

most recently provided to the EPA for 

the recipients and would include 

information on how to contact the EPA 

with any questions. The EPA proposes 

that no allocations of Group 3 

allowances would be recorded in a 

source’s compliance account until all 

the source’s surrender requirements 

with regard to 2023–2024 Group 2 

allowances have been met. For this 

reason, the principal consequence to a 

source of failure to fully comply with 

the surrender requirements by 15 days 

after the effective date of a final rule 

would be that any Group 3 allowances 

allocated to the units at the source for 

the 2023 and 2024 control periods that 

would otherwise have been recorded in 

the source’s compliance account by 30 

days after the effective date of a final 

rule would not be recorded as of that 

recordation date. 

If all surrender requirements of 2023– 

2024 Group 2 allowances for a source 

have not been met in EPA’s first 

attempt, the EPA would make a second 

attempt to complete the required 

deductions from the source’s 

compliance account (or from a specified 

general account, in the limited 

circumstance noted above) as soon as 

practicable on or after September 15, 

2023. The order in which Group 2 

allowances are deducted would be the 

same as described above for the first 

attempt. 

If the second attempt to deduct Group 

2 allowances to meet the surrender 

requirements through deductions from 

the source’s compliance account (or 


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303The proposed provision under which the EPA 

would not deduct Group 2 allowances transferred 

to unrelated parties before April 1, 2022 from the 

transferees’ accounts would not relieve the source 

to which the Group 2 allowances were originally 

allocated from the obligation to comply with the 

recall requirements. Specifically, the source would 

be required to comply with the recall requirements 

by obtaining and surrendering other Group 2 

allowances. 

304Even 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. 

305The regulations for the Group 3 Trading 

Program are at 40 CFR 97, subpart GGGGG. The 

regulations for the other five CSAPR trading 

programs are at 40 CFR part 97, subparts AAAAA, 

BBBBB, CCCCC, DDDDD, and EEEEE. 

306The regulations for the Texas SO2 Trading 

Program are at 40 CFR part 97, subpart FFFFF. 

from a specified general account) is 

unsuccessful for a given source, the EPA 

proposes that as soon as practicable on 

or after November 15, 2023, to the 

extent necessary to address the 

unsatisfied surrender requirements for 

the source, the EPA would deduct the 

2023–2024 Group 2 allowances that 

were initially recorded in the source’s 

compliance account from whatever 

accounts the allowances are held in as 

of the date of the deduction, except for 

any allowances where, as of April 1, 

2022, no person with an ownership 

interest in the allowances was an owner 

or operator of the source, was a direct 

or indirect parent or subsidiary of an 

owner or operator of the source, or was 

directly or indirectly under common 

ownership with an owner or operator of 

the source.303 Before making any 

deduction under this provision, the EPA 

would send a notification to the 

authorized account representative for 

the account in which the allowance is 

held and would provide an opportunity 

for submission of objections concerning 

the data upon which the EPA is relying. 

In EPA’s view, this provision would not 

unduly interfere with the legitimate 

expectations of participants in the 

allowance markets because the 

provision would not be invoked in the 

case of any allowance that was 

transferred to an independent party in 

an arms-length transaction before EPA’s 

intent to recall 2023–2024 Group 2 

allowances became widely known. The 

provision would apply only to a Group 

2 allowance that, as of April 1, 2022, 

was still controlled either by the owners 

and operators of the source in whose 

compliance account it was initially 

recorded or by an entity affiliated with 

such an owner or operator. The EPA 

believes that by April 1, 2022, all market 

participants will have had ample 

opportunity to become informed of the 

proposed rule provisions to recall 2023– 

2024 Group 2 allowances recorded in 

Group 3 sources’ compliance accounts, 

particularly since the EPA implemented 

a closely analogous recall of Group 2 

allowances in the Revised CSAPR 

Update.304

The EPA proposes that failure of a 

source’s owners and operators to 

comply with the surrender requirements 

would be subject to possible 

enforcement as a violation of the CAA, 

with each allowance and each day of the 

control period constituting a separate 

violation. 

To eliminate any possible uncertainty 

regarding the amounts of Group 2 

allowances allocated for the 2023–2024 

control periods (or earlier control 

periods) that the owners and operators 

of each Group 3 source would be 

required to surrender under the recall 

provisions, the EPA has prepared a list 

of the sources in the proposed 

additional Group 3 states and areas of 

Indian country in whose compliance 

accounts allocations of 2023–2024 

Group 2 allowances were recorded, with 

the amounts of the allocations recorded 

in each such compliance account for the 

2023 and 2024 control periods. An 

additional list shows, for each newly 

added Group 3 source, the specific 

Group 2 allowances (batched by serial 

number) allocated for each control 

period and recorded in the source’s 

compliance account and indicates 

whether, as of December 31, 2021, that 

batch of allowances was held in the 

source’s compliance account, in an 

account believed to be partially or fully 

controlled by a related party (i.e., an 

owner or operator of the source or an 

affiliate of an owner or operator of the 

source), or in an account believed to be 

fully controlled by independent parties. 

The lists are in a spreadsheet titled, 

‘‘Recall of Additional CSAPR NOX

Ozone Season Group 2 Allowances’’, 

available in the docket for this proposed 

rule. After the first and second 

surrender deadlines, the EPA intends to 

update the lists to indicate for each 

Group 3 source whether the surrender 

requirements for the source under the 

recall provisions have been fully 

satisfied. The EPA would post the 

updated lists on a publicly accessible 

website to ensure that all market 

participants have the ability to 

determine which specific 2023–2024 

Group 2 allowances initially recorded in 

any given Group 3 source’s compliance 

account do or do not remain subject to 

potential deduction to address the 

source’s surrender requirements under 

the recall provisions. 

The EPA requests comment on the 

proposal to recall Group 2 allowances 

equivalent in quantity and usability to 

the Group 2 allowances previously 

issued for the 2023 and 2024 control 

periods and recorded in the compliance 

accounts of sources in jurisdictions 

being newly added to the Group 3 

trading program in this proposed rule. 

12. Conforming Revisions to Other 

Regulations 

As noted in Section VII.B.1.a of this 

proposed rule, in addition to the Group 

3 trading program, EPA currently 

administers five other CSAPR trading 

programs, all of which have provisions 

that in most respects parallel the 

provisions of the Group 3 trading 

program.305 The EPA also administers 

the Texas SO2 Trading Program, whose 

provisions parallel the provisions of the 

CSAPR trading programs to a somewhat 

lesser extent.306 In this rulemaking, in 

addition to the proposed revisions to the 

Group 3 trading program, the EPA is 

proposing a small number of 

conforming revisions to the other 

CSAPR trading programs and/or the 

Texas SO2 Trading Program to maintain 

consistency across the regulations for 

the various trading programs to the 

extent possible. 

The first set of proposed conforming 

revisions concerns the use of the term 

‘‘Indian country’’ in the allowance 

allocation provisions of the regulations 

for all the CSAPR trading programs. As 

discussed in Section VII.B.9.a of this 

proposed rule, to reflect the D.C. 

Circuit’s holding in ODEQ v. EPA that 

states have initial CAA implementation 

planning authority in non-reservation 

areas of Indian country until displaced 

by a demonstration of tribal jurisdiction 

over such an area, the EPA is proposing 

to revise the allowance allocation 

provisions in the Group 3 trading 

program regulations so that, instead of 

distinguishing between the sets of units 

within a given state’s borders that either 

are not or are in Indian country, the 

revised regulations would distinguish 

between (1) the set of units within the 

state’s borders that are not in Indian 

country or are in areas of Indian country 

covered by the state’s CAA 

implementation planning authority and 

(2) the set of units within the state’s 

borders that are in areas of Indian 

country not covered by the state’s CAA 

implementation planning authority. For 

the same reasons stated in Section 

VII.B.9.a of this proposed rule for the 


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307The regulations for the various programs 

already establish a common recordation schedule 

for the portion of each state emissions budget set 

aside for possible allocation to new units—namely, 

by May 1 of the year after the year of the relevant 

control period. The related deadline for states to 

submit any state-determined allocations of these 

allowances to the EPA under each program is April 

1 of the year after the year of the relevant control 

period. 

308 If an emissions unit installs SCR or SNCR to 

meet an emissions limit in response to the proposed 

FIP that would be a physical change under new 

source review (NSR) and lead to an assessment of 

potential emissions changes. If the installation of 

SCR results in an emissions increase that exceeds 

the thresholds in the NSR regulations for one or 

more regulated NSR pollutants, including the 

Group 3 trading program, the EPA 

proposes to make revisions to the 

allowance allocation provisions in the 

regulations for all the other CSAPR 

trading programs establishing the same 

substantive distinction among the sets 

of units within each state’s borders. The 

specific regulatory provisions that 

would be affected are identified in 

Section X of this proposed rule. The 

EPA is unaware of any currently 

operating units that would be affected 

by this proposed revision to the 

regulations for the other CSAPR trading 

programs. 

The second set of proposed 

conforming revisions concerns the 

schedule for recording allocations of 

allowances to existing units. To 

maintain consistency with the 

provisions of the revised Group 3 

Trading Program to the extent possible, 

the EPA proposes to revise the 

regulations for each of the other five 

CSAPR trading programs and the Texas 

SO2 Trading Program to reflect whatever 

revised schedule for recording most 

allowance allocations the EPA may 

adopt for the revised Group 3 trading 

program in a final rule in this 

rulemaking. The proposed revisions to 

the recordation deadlines would affect 

only the timing of recordation, not the 

amounts of allowances allocated to and 

recorded for any source for any control 

period. 

The effect of the proposed revisions 

would be to establish a new common 

recordation schedule for all the CSAPR 

trading programs and the Texas SO2

Trading Program. Assuming the 

common schedule adopted is the 

specific schedule proposed for the 

Group 3 trading program in Section 

VII.B.9 of this proposed rule, allocations 

from the portion of each state emissions 

budget under each program not reserved 

in a set-aside would be recorded by July 

1 of the year immediately preceding the 

year of the relevant control period. 

Under the current regulations before the 

proposed revisions, the equivalent 

recordation deadline is July 1 of the year 

three years before the year of the 

relevant control period. Relatedly, the 

EPA also proposes to revise the deadline 

for states to submit any state-determined 

allocations to the EPA under each 

trading program to June 1 of the year 

immediately preceding the year of the 

relevant control period, instead of June 

1 of the year three years before the year 

of the relevant control period.307

This EPA believes that revising the 

recordation schedules as proposed to 

establish a new common recordation 

schedule for the affected trading 

programs would make the programs 

procedurally more consistent, generally 

reducing the time and cost expended by 

sources to understand and comply with 

multiple trading programs. Greater 

consistency across the various programs 

would also support greater 

administrative efficiency by the EPA 

and by states that elect to determine 

allowances allocations under the 

various programs. In addition, by 

reducing the number of future control 

periods for which allowances are 

recorded, the proposed revisions would 

reduce the likelihood that the EPA 

might need to recall already-recorded 

allowances as part of a transition for 

some sources to new regulatory 

requirements in a future rulemaking. 

The EPA has implemented such a recall 

in the Revised CSAPR Update and has 

proposed to implement a similar recall 

in this rulemaking. 

Finally, the EPA believes that revising 

the recordation schedules for the other 

CSAPR trading programs and the Texas 

SO2 Trading Program as proposed 

would not adversely impact allowance 

market liquidity. Allowances issued for 

control periods through 2024 under 

each of these programs were recorded 

by July 1, 2020. As of December 2021, 

although recorded private transfers of 

earlier vintage allowances usable for 

2021 compliance have been increasing 

in advance of the upcoming June 1, 

2022, compliance deadline for the 2021 

control periods, few allowances 

recorded for the 2023 or 2024 control 

periods (or even the 2022 control 

period) under any of the programs have 

been transferred out of the accounts in 

which they were initially recorded, 

except as needed to comply with the 

recall of certain allowances under the 

Revised CSAPR Update. Moreover, most 

of the recorded transfers of allowances 

issued for 2022, 2023, and 2024 have 

been between accounts controlled by 

the same entity, corporate affiliates, or 

other related entities (such as unit coowners) rather than between accounts 

controlled by unrelated parties. The 

EPA therefore believes there would have 

been little effect on arms-length 

allowance market activity in these 

programs if the proposed revised 

recordation schedule had already been 

in effect and the allowances for 2023 

and 2024 consequently had not yet been 

recorded. 

Further details on the specific 

regulatory provisions that would be 

affected by the proposed revisions to 

allowance allocation recordation 

schedules are provided in Section X of 

the proposed rule. 

The EPA requests comment on the 

proposed revision to the definition of 

‘‘Indian country’’ under the CSAPR NOX

Annual, NOX Ozone Season Group 1, 

SO2 Group 1, SO2 Group 2, and NOX

Ozone Season Group 2 Trading 

Programs and the proposed revisions to 

the allowance allocation recordation 

deadlines under the CSAPR NOX

Annual, NOX Ozone Season Group 1, 

SO2 Group 1, SO2 Group 2, and NOX

Ozone Season Group 2 Trading 

Programs and the Texas SO2 Trading 

Program. 

C. Regulatory Requirements for NonEGUs 

The EPA is proposing that the FIPs for 

23 of the states covered in this proposed 

rule will include new emissions 

limitations on emissions units in seven 

non-EGU industries that EPA finds (as 

discussed in Section VI of this proposed 

rule) to be significantly contributing to 

nonattainment or interfering with 

maintenance in other states. 

In order to achieve the necessary nonEGU emissions reductions for the 23 

states, the EPA proposes emissions 

limitations for the most impactful units 

in the relevant industries that are 

achievable with the control technologies 

identified in the Step 3 analysis. The 

EPA is proposing a direct control 

approach with rate-based limits, 

production-based limits, and work 

practice standards set on a uniform 

basis for the different segments of nonEGU emissions units using applicability 

criteria based on size and type of unit 

and, in some cases, emissions 

thresholds. The EPA believes this 

approach can achieve the requisite level 

of emissions reductions from the 

covered units through the assignment of 

emissions limits that are achievable 

across the entire segment. The EPA 

believes that establishing emissions 

limits for emissions units based on size 

and type of unit and, in some cases, 

emissions thresholds, will achieve the 

necessary reductions without requiring 

a unit-by-unit assessment.308 By 


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netting analysis, the changes would trigger the 

applicability of NSR. 

309https://www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert. 

establishing uniform emissions limits 

for categories of units rather than on a 

unit-by-unit basis, the EPA can also 

ensure that any new source of emissions 

constructed after this proposed 

rulemaking are also subject to the 

emissions limits identified later (see 

Section IV.B.1.d of this proposed rule). 

The EPA recognizes that the 

numerous variables that contribute to 

differences in units’ emissions rates may 

complicate development of limits for 

groups of units as large as those 

addressed in this proposed rule. For 

each emissions source category, the EPA 

considered the range of emissions limits 

that currently apply to these sources 

under other CAA programs, such as 

RACT, NSPS, NESHAP, and OTC model 

rules, to develop an emissions limit that 

should be achievable by all sources after 

installing the controls identified in the 

Step 3 analysis. For a detailed 

discussion of the technical bases for 

EPA’s proposed requirements for nonEGU emissions units, see the Non-EGU 

Sectors TSD. 

The EPA is proposing that the 

emissions limits and compliance 

requirements for non-EGUs will apply 

only during the ozone season (which 

runs annually from May–September). 

This is consistent with EPA’s prior 

practice in federal actions to eliminate 

significant contribution of ozone in the 

1998 NOX SIP Call, CAIR, CSAPR, 

CSAPR Update, and the Revised CSAPR 

Update. EPA is seeking comment on 

whether non-EGU sources would run 

controls that would be installed as a 

result of this proposed FIP year-round 

(i.e., will some source categories run 

their controls year-round due to the 

nature of those controls?). 

In addition, the EPA proposes to 

apply the FIP requirements to all 

existing emissions units and any future 

emissions units constructed after the 

promulgation of a final rule. Further, the 

non-EGU emissions limits and 

compliance requirements will apply in 

all 23 states (and, as discussed in 

Section IV.C.2 of this proposed rule, in 

areas of Indian country within the 

borders of those states), even if some of 

those states do not currently have 

emissions units in a particular source 

category. This approach will ensure that 

all new sources constructed in any of 

the 23 states will be subject to the same 

regulatory requirements as applied for 

the existing units under this proposed 

rule. This will also mitigate any 

potential incentive to move production 

from an existing non-EGU source in one 

linked state to a new non-EGU source of 

the same type but lacking the relevant 

emissions control requirements in 

another linked state. 

At this time, this EPA is not 

proposing to include non-EGUs in the 

trading program described in this 

proposed rule. If EPA were to include 

non-EGUs in the trading program, we 

would require monitoring and reporting 

of hourly mass emissions in accordance 

with 40 CFR part 75 as we have required 

for all trading programs. Monitoring and 

reporting under part 75 include CEMS 

(or an approved alternative method), 

rigorous initial certification testing, and 

periodic quality assurance testing 

thereafter, such as relative accuracy test 

audits and daily calibrations. This type 

of consistent and accurate measurement 

of emissions is necessary to ensure each 

allowance actually represents one ton of 

emissions and that one ton of reported 

emissions from one source would be 

equivalent to one ton of reported 

emissions from another source. See 75 

FR 45325 (August 2, 2010). Moreover, 

these monitoring requirements generally 

would need to be in place for at least 

one full ozone season to establish 

baseline data before it would be 

appropriate to rely on a trading program 

as the mechanism to achieve the 

required emissions reductions. 

Therefore, at this time, the EPA believes 

that applying unit-level emissions 

limitations on non-EGU emissions units 

rather than constructing an emissions 

trading regime is more administratively 

feasible and more easily implementable 

at the source level, and it will 

effectively eliminate each state’s 

significant contribution without the 

need for establishing a new emissions 

trading program. 

The EPA is proposing to require 

electronic reporting for all seven nonEGU industries. Specifically, owners 

and operators of affected units must 

submit electronic copies of required 

performance test reports, performance 

evaluation reports, quarterly and semiannual reports, and excess emissions 

reports through EPA’s Central Data 

Exchange (CDX) using the Compliance 

and Emissions Data Reporting Interface 

(CEDRI). The EPA is proposing to 

require that performance test results 

collected using test methods that are 

supported by EPA’s Electronic 

Reporting Tool (ERT) as listed on the 

ERT website 309 at the time of the test be 

submitted in the format generated 

through the use of the ERT or an 

electronic file consistent with the xml 

schema on the ERT website, and that 

other performance test results be 

submitted in portable document format 

(PDF) using the attachment module of 

the ERT. Similarly, the EPA is 

proposing to require that performance 

evaluation results of CEMS measuring 

relative accuracy test audit (RATA) 

pollutants that are supported by the ERT 

at the time of the test be submitted in 

the format generated through the use of 

the ERT or an electronic file consistent 

with the xml schema on the ERT 

website, and that other performance 

evaluation results be submitted in PDF 

using the attachment module of the 

ERT. In addition, the EPA is proposing 

to require that quarterly and semiannual reports and excess emissions 

reports be submitted in PDF uploaded 

in CEDRI. 

The EPA is proposing to allow for an 

extension of time to file a report where 

an owner or operator demonstrates that 

it cannot meet the reporting deadline for 

reasons outside of its control. 

Specifically, the EPA has identified two 

broad circumstances under which the 

EPA may grant a request for an 

extension of time to file an electronic 

report. These circumstances are (1) 

outages of EPA’s CDX or CEDRI which 

preclude an owner or operator from 

accessing the system and submitting 

required reports and (2) force majeure 

events, which are defined as events that 

will be or have been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevent an owner or operator from 

complying with the requirement to 

submit a report electronically. Examples 

of force majeure events are acts of 

nature, acts of war or terrorism, or 

equipment failure or safety hazards 

beyond the control of the facility. In 

both circumstances, the decision to 

grant an extension of time to report is 

within the discretion of the 

Administrator, and reporting should 

occur as soon as possible. 

Electronic submittal of required 

reports will increase the usefulness of 

the data contained in those reports, is in 

keeping with current trends in data 

availability and transparency, will 

further assist in the protection of public 

health and the environment, will 

improve compliance by facilitating the 

ability of regulated facilities to 

demonstrate compliance with 

requirements and by facilitating the 

ability of the EPA to assess and 

determine compliance, and will 

ultimately reduce burden on regulated 

facilities and the EPA. Electronic 

reporting also eliminates paper-based, 

manual processes, thereby saving time 

and resources, simplifying data entry, 

eliminating redundancies, minimizing 


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310EPA’s Final Plan for Periodic Retrospective 

Reviews, August 2011. Available at: https://

www.regulations.gov/document?D=EPA-HQ-OA2011-0156-0154. 311E-Reporting Policy Statement for EPA 

Regulations, September 2013. Available at: https:// 

www.epa.gov/sites/production/files/2016-03/ 

documents/epa-ereporting-policy-statement-2013- 

09-30.pdf. 

312 Digital Government: Building a 21st Century 

Platform to Better Serve the American People, May 

2012. Available at: https://obamawhitehouse.

archives.gov/sites/default/files/omb/egov/digitalgovernment/digital-government.html. For more 

information on the benefits of electronic reporting, 

see the memorandum Electronic Reporting 

Requirements for New Source Performance 

Standards (NSPS) and National Emission 

Standards for Hazardous Air Pollutants (NESHAP) 

Rules, referenced earlier in this section. 

313Ozone Transport Commission, Technical 

Information Oil and Gas Sector Significant 

Stationary Sources of NOX Emissions, 35–39, 

October 17, 2012. 

data reporting errors, and providing data 

quickly and accurately to the affected 

facilities, air agencies, EPA, and the 

public. Moreover, electronic reporting is 

consistent with EPA’s plan 310 to 

implement Executive Order 13563 and 

is in keeping with EPA’s agency-wide 

policy 311 developed in response to the 

White House’s Digital Government 

Strategy.312

The EPA notes that no emissions 

standard or other requirement 

established for non-EGUs in these FIPs 

may be interpreted, construed, or 

applied to diminish or replace the 

requirements of any emissions 

limitation or other applicable 

requirement established by the 

Administrator pursuant to other CAA 

authority or a standard issued under 

State authority. 

1. Pipeline Transportation of Natural 

Gas 

Applicability 

The EPA is proposing to establish 

regulatory requirements for the Pipeline 

Transportation of Natural Gas industry 

that apply to stationary, natural gasfired, spark ignited reciprocating 

internal combustion engines 

(‘‘stationary SI engines’’) within these 

facilities that have a maximum rated 

capacity of 1,000 horsepower (hp) or 

greater. Based on our review of the 

potential emissions from stationary SI 

engines, we find that use of a maximum 

rated capacity of 1,000 hp reasonably 

approximates the selection of 100 tpy 

used within the non-EGU screening 

assessment. Therefore, stationary SI 

engines subject to the proposed rule 

requirements of this section are those 

found within any of the 23 covered 

states with non-EGU emissions 

reduction obligations that are within the 

Pipeline Transportation of Natural Gas 

industry and have a maximum rated 

capacity of 1,000 hp or greater. 

Emissions Limitations and Rationale 

In developing the emissions limits for 

the Pipeline Transportation of Natural 

Gas industry, EPA reviewed RACT NOX

rules, air permits, and OTC model rules. 

While some permits and rules express 

engine emissions limits in parts per 

million by volume (pmmv), the majority 

of rules and source-specific 

requirements express the emissions 

limits in grams per horsepower per hour 

(g/hp-hr). The EPA has historically set 

emissions limits for these types of 

engines using g/hp-hr and finds that 

method appropriate for this proposed 

FIP as well. 

Based on the available information for 

this industry, applicable State and local 

air agency rules, and active air permits 

issued to sources with similar engines, 

the EPA is proposing the following 

emissions limits for stationary SI 

engines in the covered states: 

TABLE VII.C–1—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR PIPELINE TRANSPORTATION OF NATURAL GAS

Engine type and fuel Proposed NOX emissions 

limit Additional information 

Natural Gas Fired Four Stroke Rich Burn ........................ 1.0 g/hp-hr .......................... Limits reviewed ranged between 0.2 and 3.0 g/hp-hr. 

Natural Gas Fired Four Stroke Lean Burn ....................... 1.5 g/hp-hr .......................... Limits reviewed ranged between 0.5 and 3.0 g/hp-hr. 

Natural Gas Fired Two Stroke Lean Burn ........................ 3.0 g/hp-hr .......................... Limits reviewed ranged between 0.5 and 3.0 g/hp-hr. 

With regard to four stroke rich burn 

engines, the EPA is proposing an 

emissions limit of 1.0 g/hp-hr. This 

limit is designed to be achievable by 

installing Non-Selective Catalytic 

Reduction (NSCR) on existing four 

stroke rich burn engines, as identified in 

the non-EGU screening assessment. 

Sources are free to install another 

control technology besides NSCR as 

long as the unit is still able to meet the 

emissions limit. In particular for four 

stroke rich burn engines, NSCR can be 

an effective control technology due to 

the low oxygen percentage in the 

exhaust. Efficient operation of the 

catalyst in NSCR requires the engine 

exhaust gases contain no more than 0.5 

percent oxygen, which makes rich burn 

engines uniquely suitable to NCSR. 

Given that NSCR can achieve NOX

reductions of 90 to 99 percent, the EPA 

believes an emissions limit of 1.0 g/hphr should be readily achievable by all 

four stroke rich burn engines subject to 

this proposed rulemaking. The EPA is 

taking comment on whether a lower 

emissions limit is more appropriate 

since even an assumed reduction of 95 

percent would result in most engines 

being able to achieve an emissions rate 

of 0.5 g/hp-hr. However, at this time, the 

EPA does not have the information 

necessary to determine if a lower 

emissions limit is achievable for the 

four stroke rich burn engines subject to 

the proposed rulemaking, and therefore, 

the EPA is proposing an emissions limit 

of 1.0 g/hp-hr. 

With regard to four stroke lean burn 

engines, the EPA is proposing an 

emissions limit of 1.5 g/hp-hr. This 

limit is designed to be achievable by 

installing SCR on existing four stroke 

lean burn engines. Sources are free to 

install another control technology with 

or without SCR as long as the unit is 

still able to meet the emissions limit. 

For example, it might be more cost 

effective on an ongoing basis for some 

four stroke lean burn engines to install 

layered combustion controls alone or 

along with SCR to achieve the necessary 

emissions reductions. Information 

available to the EPA suggests that some 

four stroke lean burn engines can 

achieve 90% reductions from layered 

combustion controls alone, such as 

turbochargers and inter-cooling, prechamber ignition or high energy 

ignition, improved fuel injection 

control, air/fuel ratio control.313

Independent of unit specific 

considerations, the EPA believes that 

four stroke lean burn engines subject to 

this proposed FIP can achieve an 

emissions limit of 1.5 g/hp-hr with the 

installation and operation of SCR or 

other control technologies at the 

marginal cost threshold of $7,500 per 


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314Ozone Transport Commission, Technical 

Information Oil and Gas Sector Significant 

Stationary Sources of NOX Emissions at 24–25. 

ton identified in the non-EGU screening 

assessment. While a lower emissions 

limit may be achievable with SCR for 

some four stroke lean burn engines, the 

achievability of those lower limits may 

depend on engine age and come with 

increased costs not accounted for in this 

proposed rule. The EPA is seeking 

comment on whether a lower and higher 

emissions limit is appropriate for these 

units. 

For two stroke lean burn engines, the 

EPA is currently proposing an emissions 

limit of 3.0 g/hp-hr. This limit is 

designed to be achievable by retrofitting 

existing two stroke lean burn engines 

with layered combustion to achieve this 

emissions limit. Sources are free to 

install another control technology 

besides layered combustion as long as 

the unit is still able to meet the 

emissions limit. As identified in the 

non-EGU screening assessment, the EPA 

believes that layered combustion 

controls, such as improved airflow, 

improved fuel to air mixing, improved 

ignition, and modern engine electronic 

controls can be achieved on two stroke 

engines at the marginal cost threshold of 

$7,500 per ton. With these types of 

controls, the information currently 

available to the EPA indicates that the 

amount of achievable emissions 

reductions is unit specific and can range 

from a 60 to 90 percent reduction in 

NOX emissions. The EPA estimates that 

existing uncontrolled two stroke lean 

burn engines would need to reduce 

emissions by about 80 percent to 

comply with a 3.0 g/hp-hr emissions 

limit. While some RACT and model 

rules reviewed contained more stringent 

emissions limits for two stroke lean 

burn engines, the EPA does not have 

information adequate to conclude that 

the two stroke lean burn engines across 

all 23 states can meet a lower limit. 

Further, some information available 

supports a finding that an emissions 

limit below 3.0 g/hp-hr might not be 

achievable with layered combustion 

controls alone for some units, and those 

units would require additional controls 

beyond our cost threshold.314 Therefore, 

the EPA is proposing an emissions limit 

of 3.0 g/bhp-hr for two stroke engines. 

The EPA is seeking comment on 

whether a lower emissions limit would 

be achievable with layered combustion 

alone for the sources covered by this 

FIP. Further, the EPA is seeking 

comment on whether additional control 

technology could be installed on these 

sources at or below the marginal cost 

threshold to achieve a lower emissions 

rate. 

Compliance Assurance Requirement 

The EPA is proposing to require 

stationary SI engines subject to this 

proposed FIP to conduct semi-annual 

performance testing in accordance with 

40 CFR 60.8 to ensure that the engine 

is meeting the NOX emissions limit. The 

EPA is proposing that affected engines 

then monitor and record hours of 

operation and fuel consumption to 

calculate ongoing compliance with the 

applicable emissions limit. In addition, 

the EPA is proposing that affected 

engines would use continuous 

parametric monitoring systems (CPMS) 

to ensure that the NOX emissions limit 

is being met at all times. For example, 

engines utilizing layered combustion 

controls would need to monitor and 

record temperature, air to fuel ratio, and 

other parameters as appropriate to 

ensure that combustion conditions are 

optimized to reduce NOX emissions and 

assure compliance with the emissions 

limit. For engines using SCR or NSCR, 

the EPA is proposing that source 

monitor and record parameters such as 

inlet temperature to the catalyst and 

pressure drop across the catalyst. 

The EPA is seeking comment on 

whether it is feasible or appropriate to 

require affected engines to be equipped 

with continuous emissions monitoring 

systems (CEMS) to measure and monitor 

the NOx emissions instead of 

conducting performance tests on a 

semiannual basis. 

2. Cement and Concrete Product 

Manufacturing 

Applicability 

The EPA is proposing to establish 

regulatory requirements for the Cement 

and Concrete Product Manufacturing 

source category that apply to emissions 

units (kilns) that directly emit or have 

the potential to emit 100 tpy or more of 

NOX. Further, the EPA is proposing 

emissions limits based on type of unit 

to ensure that the necessary NOX

emissions reductions occur. The EPA is 

seeking comment on whether it should 

set an applicability threshold based on 

a unit’s design production capacity 

rather than an emissions threshold. 

Emissions Limitations and Rationale 

In developing the emissions limits for 

the Cement and Concrete Manufacturing 

industry, the EPA reviewed RACT NOX

rules, air permits, and consent decrees. 

These rules and source-specific 

requirements most commonly express 

the emissions limits for this industry in 

terms of mass of pollutant emitted 

(pounds) per kiln’s clinker output 

(tons), i.e., pounds of NOX emitted per 

ton of clinker produced. A regulated 

entity routinely monitors and keeps 

track of its clinker output as it pertains 

to a kiln design capacity and the plant’s 

production. Therefore, the EPA believes 

that this form of NOX emissions limit is 

effective, practicable and convenient to 

record and report to an air agency. 

In determining the averaging time for 

the limit, the EPA considered the NSPS 

for Portland Cement Plants at 40 CFR 

part 60, subpart F. Section 60.62(a)(3) of 

this subpart establishes a 30-operating 

day rolling average period for the NOX

emitted per ton of clinker produced and 

further states that an operating day 

includes all valid data obtained in any 

daily 24-hour period during which the 

kiln operates and excludes any 

measurements made during the daily 

24-hour period when the kiln was not 

operating. In addition, 40 CFR 60.44b(i) 

requires that compliance with the 

applicable NOX emissions limit be 

determined on a 30-day rolling average 

basis. The EPA is proposing to require 

a 30-operating day rolling average 

period as the averaging time frame for 

this particular industry. The proposed 

averaging timeframe is consistent with 

the longstanding national technologybased NSPS for this industry at 40 CFR 

part 60, subpart F. Furthermore, an air 

agency may choose to require an 

averaging period shorter than a 30- 

operating day rolling average in air 

permit(s) issued to these plants. The 

EPA finds that a 30-operating day 

rolling average period provides a 

reasonable balance between short term 

(hourly or daily) and long term (annual) 

averaging periods, while being flexible 

and responsive to fluctuations in 

operations and production. 

Based on the available information for 

this industry, applicable State and local 

air agency rules, and active air permits 

or enforceable orders issued to affected 

cement plants, the EPA is proposing the 

following emissions limits for cement 

kilns: 


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315 85 FR 68999 (October 30, 2020). 

TABLE VII.C–2—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR KILN TYPES IN CEMENT AND CONCRETE PRODUCT

MANUFACTURING

Kiln type 

Proposed NOX

emissions limit 

(lb/ton of clinker) 

Additional information 

Long Wet ........................ 4.0 Limits reviewed ranged between 3.88–5.2; one State rule allows as high as 6.0; with addition of a post combustion NOX control the upper range could be reduced significantly. 

Long Dry ......................... 3.0 Limits reviewed showed 5.1; with addition of post combustion NOX control the limit could 

be reduced significantly; limit of 3.0 would achieve a 41% reduction in NOX emissions. 

Preheater ........................ 3.8 Limits reviewed ranged between 1.5–3.44; limit of 3.8 is consistent with 30 TAC 

117.3110(a)(3) and 35 IAC 217.224(a). 

Precalciner ..................... 2.3 Requires post combustion NOX control; consistent with permit A0017 for Lehigh Southwest 

Cement Company issued on May 5, 2020 by the Bay Area Air Quality Management District. 

Preheater/Precalciner ..... 2.8 Limits reviewed ranged between 1.8–3.4; limit of 2.8 is consistent with 30 TAC 

117.3110(a)(4); Mitsubishi Cement Corporation Lucerne Valley Federal Operating Permit 

11800001 issued by the Mojave Desert Air Quality Management District (MDAQMD) 

June 18, 2020; MDAQMD Rule 1161 (C)(2); and Illinois 35 IAC 217.224(a). 

Although the EPA is proposing NOX

emissions limits based on the specific 

kiln types listed in Table VII.C–2, to 

provide operational flexibility the EPA 

is also proposing a source cap limit 

expressed in tons per day (tpd) of NOX

for each individual cement plant 

according to the following equation. 

Where: 

CAP2015 Ozone Transport = total allowable 

NOX emissions from all cement kilns 

located at one cement plant, in tons per 

day, on a 30-operating day rolling 

average basis; 

KD = 1.7 pounds NOX per ton of clinker for 

dry preheater-precalciner or precalciner 

kilns; 

KW = 3.4 pounds NOX per ton of clinker for 

long wet kilns; 

ND = the average annual production in tons 

of clinker plus one standard deviation 

for the three most recent calendar years 

from all dry preheater-precalciner or 

precalciner kilns located at one cement 

plant; and 

NW = the average annual production in tons 

of clinker plus one standard deviation 

for the three most recent calendar years 

from all long wet kilns located at one 

cement plant. 

An affected cement plant will need to 

comply with both the source cap limit 

and the specific NOX emissions limits 

assigned to its individual kiln type(s). 

The EPA notes that the above source cap 

would be calculated and assigned to 

operating kilns in a particular plant. 

That is, the total allowable NOX

emissions in tpd from one plant cannot 

be traded with another plant, regardless 

of these plants’ control of ownership or 

operator’s status, or regardless of these 

plants’ proximity to each other or their 

location. 

The EPA is soliciting comment on 

whether it is feasible or appropriate to 

phase out and retire existing long wet 

kilns in the affected states and to 

replace them with more energy efficient 

and less emitting units like preheater/ 

precalciner installations. The EPA is 

also requesting comment on the time 

needed to complete such a task. It has 

been shown that such kilns 

replacements (preheater/precalciner 

kilns), when equipped with postcombustion NOX control devices such 

as SNCR, are capable of meeting NOX

emissions limit of 1.5 lb/ton of clinker 

on a 30-operating day basis. For this 

reason, the EPA proposes to find that 

conversion from long wet kilns to 

preheater/precalciner installations is 

generally feasible. Given that long wet 

kilns are less energy efficient and 

generally emit more NOX than other kiln 

types, conversion to preheater/ 

precalciner installations would be the 

most effective method of NOX reduction 

(per ton of clinker produced). 

Additionally, EPA is soliciting 

comments on whether it is feasible or 

appropriate to require sources with 

existing preheater/precalciner kilns in 

the affected states that currently utilize 

low NOX burners, combustion controls, 

staged combustion, or mid-kiln firing to 

add and operate a post combustion 

control device like SNCR or SCR to 

further improve their NOX removal 

efficiency and lower NOX emissions to 

1.95 lb/ton of clinker or less. The EPA 

is also requesting comments on the time 

needed to complete such an addition. 

We note that the EPA previously stated 

that it expects that the controls for 

cement kilns would take at least 2 years 

to install on a sector-wide basis across 

the 12-state region affected by the 

Revised CSAPR Update.315

Compliance Assurance Requirements 

The EPA is proposing that 

performance tests be conducted on a 

semiannual basis. Such tests shall be 

conducted in conformance with the 

requirements of 40 CFR 60.8. Stack tests 

will need to conform with the Test 

Methods and Procedures in 40 CFR 60 

appendix A, or other EPA-approved 

(federally enforceable) test methods and 

procedures. 

The EPA is soliciting comments on 

whether it is feasible or appropriate to 

require affected units (kilns) to be 

equipped with CEMS to measure and 

monitor the NOX concentration 

(emissions level) instead of conducting 

performance tests on semiannual basis. 

We are also soliciting comment on 

whether it is appropriate for the affected 

units (kilns) to use CPMS instead of 

CEMS to monitor the NOX concentration 

(emissions level). We note that CPMS, 

also called parametric monitoring, 

measures a parameter (or multiple 

parameters) as a key indicator of system 

performance. The parameter is generally 

an operational parameter of the process 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20145 

or the air pollution control device 

(APCD) that is known to affect the 

emissions levels from the process or the 

control efficiency of the APCD. 

Examples of parametric monitoring 

include kiln feed rate, clinker 

production rate, fuel type, fuel flow rate, 

specific heat consumption, secondary 

air temperature, kiln feed-end 

temperature, preheater exhaust gas 

temperature, induced draught fan 

pressure drop, kiln feed-end percentage 

oxygen, percentage downcomer oxygen, 

primary air flow rate, ammonia feed rate 

and slippage. 

3. Iron and Steel Mills and Ferroalloy 

Manufacturing 

Applicability 

The EPA is proposing to establish 

regulatory requirements for the Iron and 

Steel Mills and Ferroalloy 

Manufacturing source category that 

apply to emissions units that directly 

emit or have the potential to emit 100 

tpy or more of NOX and to facilities 

containing two or more such units that 

collectively emit or have the potential to 

emit 100 tpy or more of NOX. The EPA 

is setting emissions limits based on type 

of unit to ensure that the necessary 

emissions reductions occur across all 

units of the same type. The EPA is 

seeking comment on whether it should 

set an applicability threshold based on 

a unit’s production capacity rather than 

an emissions threshold. 

Emissions Limitations and Rationale 

In developing the emissions limits for 

the Iron and Steel and Ferroalloy 

Manufacturing industry, the EPA 

reviewed RACT NOX rules, NESHAP 

rules, air permits and related emissions 

tests, technical support documents, and 

consent decrees. These rules and 

source-specific requirements most 

commonly express the emissions limits 

for this industry in terms of mass of 

pollutant emitted (pounds) per 

operating hour (hours) (i.e., pounds of 

NOX emitted per production hour), 

pounds per energy unit (i.e., million 

British thermal unit (mmBtu)), or 

pounds of NOX per ton of steel 

produced. A regulated entity routinely 

monitors and keeps track of its 

production in terms of tons of steel 

produced per hour (heat rate) as it 

pertains to the facility’s rate of iron and 

steel production. Depending on the type 

of unit and industry practice, the EPA 

is proposing rate-based emissions limits 

in the form of lb/mmBtu, productionbased limits in the form of lb/ton, and 

work practice standards. 

In determining the averaging times for 

the limits, EPA initially reviewed the 

NESHAP for Iron and Steel Foundries 

codified at 40 CFR part 63 subpart 

EEEEE, the NESHAP for Integrated Iron 

and Steel manufacturing facilities 

codified at 40 CFR part 63 subpart 

FFFFF, the NESHAP for Ferroalloys 

Production: Ferromanganese and 

Silicomanganese codified at 40 CFR part 

63 subpart XXX, and the NESHAP for 

Ferroalloys Production Facilities 

codified at 40 CFR part 63 subpart 

YYYYYY. EPA also reviewed various 

RACT NOX rules from states located 

within the OTR, several of which have 

chosen to implement OTC model rules 

and recommendations. Based on this 

information, the EPA is proposing to 

require a 30-operating day rolling 

average period as the averaging time 

frame for this particular industry. The 

EPA finds that a 30-operating day 

rolling average period provides a 

reasonable balance between short term 

(hourly or daily) and long term (annual) 

averaging periods, while being flexible 

and responsive to fluctuations in 

operations and production. 

Based on the available information for 

this industry, applicable federal and 

state rules, and active air permits or 

enforceable orders issued to affected 

facilities in the iron and steel and 

ferroalloy manufacturing industry, the 

EPA proposes the following emissions 

limits: 

TABLE VII.C–3—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR IRON AND STEEL AND FERROALLOY EMISSIONS

UNITS

Emissions unit 

Proposed NOX emissions 

standard or requirement 

(lbs/hour or lb/mmBtu) 

Additional information 

Blast Furnace ........................... 0.03 lb/mmBtu ......................... OH NOX RACT rules limit NOX emissions from blast furnaces to 0.06 lb/ 

mmBtu without requiring specific control technology. Control NOX at stoves 

(typically 3 or 4 per blast furnace), assuming 40–50% reduction) by burner 

replacement plus SCR. 

Basic Oxygen Furnace ............. 0.07 lb/ton ................................ Potential 25–50% reduction by SCR/SNCR from 0.14 lb/ton based on emissions testing. 

Electric Arc Furnace ................. 0.15 lb/ton steel ....................... Example permit limits at around 0.2 lb/ton. Assumes 25% reduction by SCR 

to achieve 0.15 lb/ton steel. 

Ladle/tundish Preheaters ......... 0.06 lb/mmBtu ......................... Nucor Kankakee BACT permit limit issued January 2021 is 0.1 lb/mmBtu, 

2021. Assume 40% reduction by SCR. 

Reheat furnace ......................... 0.05 lb/mmBtu ......................... Sterling Steel permit, issued 2019: Low-NOX natural gas fired burners designed to emit no more than 0.073 lb NOX/mmBtu, Ohio RACT limit is 0.09 

lb/mmBtu. Assume 40% reduction by SCR. 

Annealing Furnace ................... 0.06 lb/mmBtu ......................... Big River Steel (AR) 2018 limit and Benteler Steel (LA) 2019 limit (0.11 lb/ 

mmBtu), 85 mmBtu/hr and 13 mmBtu/hr, respectively. Lowest was 0.0915 

lb/mmBtu, Nucor AR. Assume 40% reduction by SCR. 

Vacuum Degasser .................... 0.03 lb/mmBtu ......................... 0.05 lb/mmBtu Nucor Darlington (SC) and Nucor Tuscaloosa (AL). Assume 

40% reduction by SCR. 

Ladle Metallurgy Furnace ......... 0.1 lb/ton .................................. Assume 40% reduction by SCR. 

Taconite Production Kilns ........ Work practice standard to install and operate low NOX

burners.

Consistent with requirements in Minnesota Taconite FIP See 81 FR 21671. 

Coke Ovens (charging) ............ 0.15 lb/ton of coal charged ...... Assume 50% reduction staged combustion and/or limited use SCR/SNCR 

during charging operations from AP–42 0.3 lb/ton emission factor. 

Coke Ovens (pushing) ............. 0.015 lb/ton of coal pushed ..... SunCoke Middletown limit is 0.02 lb/ton of coal. Assume 25% reduction by 

SCR. 

Boilers—Coal ............................ 0.20 lb/mmBtu ......................... See explanation in Section VII.C.5. 

Boilers—Residual oil ................ 0.20 lb/mmBtu ......................... See explanation in Section VII.C.5. 

Boilers—Distillate oil ................. 0.12 lb/mmBtu ......................... See explanation in Section VII.C.5. 


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20146 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

316RACT NOX rules of the following OTR states 

CT, DC, DE, MD, ME, NH, NY, RI, VA, and VT do 

not provide presumptive NOX limits for glass 

manufacturing sources. These RACT regulations 

require owners or operators to submit RACT caseby-case analysis. 

317Pennsylvania’s presumptive RACT NOX

emissions limits are based on 30-day rolling 

average. New Jersey’s and Massachusetts’ rules 

contain more stringent daily averages. Maryland’s 

RACT rule, section 26.11.09.08.I, requires owner or 

operators to optimize combustion by performing 

daily oxygen tests and maintain excess oxygen at 

4.5% or less. See http://www.dsd.state.md.us/ 

comar/comarhtml/26/26.11.09.08.htm. 

318For example, presumptive RACT NOX

emissions limits in California are based on both 30- 

day rolling and daily averages (see https://

www.valleyair.org/rules/currntrules/ 

R4354%20051911.pdf). Wisconsin’s NOX emissions 

limits are based on a 30-day rolling average (see 

https://casetext.com/regulation/wisconsinadministrative-code/agency-department-of-naturalresources/environmental-protection-air-pollutioncontrol/chapter-nr-428-control-of-nitrogencompound-emissions/subchapter-iv-NOXreasonably-available-control-technologyrequirements/section-nr-42822-emission-limitationrequirements). 

TABLE VII.C–3—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR IRON AND STEEL AND FERROALLOY EMISSIONS

UNITS—Continued 

Emissions unit 

Proposed NOX emissions 

standard or requirement 

(lbs/hour or lb/mmBtu) 

Additional information 

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

Due to the many types of units within 

Iron and Steel Mills and Ferroalloy 

Manufacturing facilities that are not 

currently subject to NOX limitations of 

the stringency necessary to eliminate 

significant contribution, most of the 

emissions limits in this proposed rule 

are based on examples of permitted 

emissions and estimated reduction 

potential from the identified control 

technology. Based on the selection of 

SCR, SNCR, and burner replacement in 

the non-EGU screening assessment, the 

EPA assumed reductions of 20 to 50 

percent from current permitted limits 

and emissions tests depending on the 

type of unit and controls being 

implemented. 

In addition, for Taconite Production 

Kilns, the EPA does not currently have 

the data to determine appropriate 

emissions limits that these units could 

achieve by installing low NOX burners. 

Therefore, the EPA is proposing to 

require the installation of low NOX

burners for Taconite Production Kilns 

and work practice standards for 

operating these control technologies to 

achieve emissions reductions. The EPA 

is also proposing to require these 

sources to perform performance tests 

and establish a unit-specific emissions 

limit at that time. These work practice 

standards are consistent with EPA’s 

Taconite FIP for Minnesota. See 81 FR 

21671 (April 12, 2016). Due to the 

ongoing nature of this FIP, the EPA is 

proposing to require installation of 

specific control technologies and a 

period of evaluation before setting a 

numerical emissions limit. 

Compliance Assurance Requirements 

The EPA is proposing to require each 

owner or operator of an affected facility 

that is subject to the NOX emissions 

limit for Iron and Steel Mills and 

Ferroalloy Manufacturing emissions 

units contained in this section to install, 

calibrate, maintain, and operate a CEMS 

for the measurement of NOX emissions 

discharged into the atmosphere from the 

affected facility. The EPA is proposing 

that each emissions unit will be 

required to conduct an initial 

performance test and to operate CEMS 

to assure compliance. In conducting the 

performance tests to demonstrate 

compliance, sources must use test 

methods and procedures in 40 CFR 60 

appendix A, Method 7E, or other EPAapproved (federally enforceable) test 

methods and procedures. The EPA is 

also soliciting comments on alternative 

monitoring systems or methods that are 

equivalent to CEMS to demonstrate 

compliance with the emissions limits. 

4. Glass and Glass Product 

Manufacturing 

Applicability 

The EPA is proposing to establish 

regulatory requirements for the Glass 

and Glass Product Manufacturing source 

category that apply to emissions units 

that directly emit or have the potential 

to emit 100 tpy or more of NOX. The 

EPA is setting emissions limits based on 

type of unit to ensure that the necessary 

emissions reductions occur. The EPA is 

seeking comment on whether it should 

set an applicability threshold based on 

a unit’s production capacity rather than 

an emissions threshold. 

Emissions Limitations and Rationale 

In developing the emissions limits for 

the Glass and Glass Product 

Manufacturing industry, the EPA 

reviewed RACT NOX rules, air permits, 

Alternative Control Techniques (ACT), 

and consent decrees. These rules and 

source-specific requirements most 

commonly express the emissions limits 

for this industry in terms of mass of 

pollutant emitted (pounds) per weight 

of glass removed from the furnace 

(tons), i.e., pounds of NOX emitted per 

ton of glass produced. A regulated entity 

routinely monitors and keeps track of its 

glass outputs as it pertains to a furnace’s 

design capacity and the plant’s 

production. Therefore, the EPA believes 

that this form of NOX emissions limit is 

effective, practicable, and convenient to 

record and report to an air agency. 

In determining the averaging time for 

the limits, the EPA initially reviewed 

the NSPS for glass manufacturing plants 

codified at 40 CFR part 60 subpart CC. 

This NSPS applied to any glass melting 

furnace in an affected facility that 

commenced construction or 

modification after June 15, 1979, and 

produced more than 5 tons of glass per 

day. It was noted that the NSPS only 

provides standards for particulate 

matter and does not provide standards 

or averaging times for NOX. In order to 

determine the averaging time for the 

NOX emissions limits, the EPA reviewed 

various RACT NOX rules from states 

located within the OTR, several of 

which have chosen to implement OTC 

model rules and recommendations. 

Most of the states within the OTR 

implement RACT regulations for the 

glass manufacturing industry that do not 

specify presumptive NOX limits.316

With respect to those RACT rules in the 

OTR states that contain presumptive 

RACT NOX limits for glass 

manufacturing furnaces, EPA found 

variations in averaging times, ranging 

from a 30-day rolling average to a more 

stringent daily average.317 The EPA also 

reviewed RACT NOX regulations for the 

glass manufacturing industry outside 

the OTR and observed that 30-day 

rolling averages and daily averages 

varied throughout the states.318 The 

EPA is proposing to require owners or 

operators of glass manufacturing 

furnaces to comply with the applicable 

presumptive NOX emissions limits on a 

30-day rolling average time frame. This 

averaging time frame is consistent with 

other statewide RACT NOX regulations 

for this particular industry. 

Furthermore, a state’s air agency may 

choose to require an averaging period 

shorter than a 30-operating day rolling 


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319See definitions in 40 CFR part 60 subpart CC. 320 ‘‘Alternative Control Techniques Document— 

NOX Emissions from Glass Manufacturing,’’ EPA– 

453/R–94–037, June 1994. 

321This equation is provided in the San Joaquin 

Valley Unified Air Pollution Control District’s Rule 

4354, section 8.1. 

average in air permits or RACT 

regulations for these plants. The EPA 

finds that a 30-operating day rolling 

average period provides a reasonable 

balance between short term (hourly or 

daily) and long term (annual) averaging 

periods, while being flexible and 

responsive to fluctuations in operation 

and production. 

Based on the available information for 

this industry, applicable state and local 

air agency rules, and active air permits 

or enforceable orders issued to affected 

glass manufacturing plants, EPA is 

proposing the following emissions 

limits for glass manufacturing furnaces: 

TABLE VII.C–4—SUMMARY OF PROPOSED NOX EMISSIONS LIMITS FOR FURNACE UNIT TYPES IN GLASS AND GLASS

PRODUCT MANUFACTURING

Furnace type 

Proposed NOX

emissions limit 

(lb/ton of glass 

produced) 

Additional information 

Container Glass Manufacturing Furnace.4.0 Limits reviewed ranged between 1–4; one state rule allowed as high as 5; with addition of 

post combustion NOX controls, the upper range could be reduced significantly; consistent with 25 Pennsylvania Code 129.304(a)(1) and New Jersey Administrative Code 

7:27 Subchapter 19.1. 

Pressed/Blown Glass Manufacturing Furnace or Fiberglass Manufacturing Furnace.4.0 Limits reviewed ranged between 1.36–4; one state rule allowed as high as 7; with addition 

of post combustion control the limit could be reduced significantly; limit of 4.0 is consistent with RACT regulations for states located within OTR. 

Flat Glass Manufacturing Furnace.9.2 Limits reviewed ranged between 5–9.2; with the addition of post combustion controls the 

limit could be reduced significantly; consistent with San Joaquin Valley Air Pollution Control District Rule 4354 5.1.1 and New Jersey Administrative Code 7:27 Subchapter 19.1. 

The EPA is soliciting comment on 

whether it is feasible or appropriate to 

phase out and retire existing glass 

manufacturing furnaces in the affected 

states and replace them with more 

energy efficient and less emitting units 

like all-electric melter installations. The 

EPA is also requesting comment on the 

time needed to complete such a task. 

All-electric melters are glass melting 

furnaces in which all the heat required 

for melting is provided by electric 

current from electrodes submerged in 

the molten glass.319 All-electric melter 

furnaces could provide an energy 

efficient and NOX emission-free 

alternative to current methods of 

melting and producing glass. 

According to the EPA’s ‘‘Alternative 

Control Techniques Document—NOX

Emissions from Glass 

Manufacturing,’’ 320 glass manufacturing 

furnaces may utilize combustion 

modifications equivalent to low-NOX

burners and oxy-firing. The EPA is 

soliciting comment on whether it is 

feasible or appropriate to require 

sources with existing glass 

manufacturing furnaces in affected 

states that currently utilize these 

combustion modifications to add and 

operate a post-combustion control 

device like SNCR and SCR to further 

improve their NOX removal efficiency. 

The EPA is also requesting comments 

on the time needed to install such 

controls. 

Compliance Assurance Requirements 

The EPA is proposing to require each 

owner or operator of an affected facility 

that is subject to the NOX emissions 

standards for glass manufacturing 

furnaces contained in this section to 

install, calibrate, maintain, and operate 

a CEMS for the measurement of NOX

emissions discharged into the 

atmosphere from the affected facility. 

The EPA is also soliciting comments on 

alternative monitoring systems or 

methods that are equivalent to CEMS to 

demonstrate compliance with the 

emissions limits. In conducting the 

performance tests to demonstrate 

compliance, sources must use test 

methods and procedures in 40 CFR part 

60 appendix A, method 7E, or other 

EPA-approved (federally enforceable) 

methods and procedures. Owners or 

operators must calculate and record the 

30-operating day rolling emissions rate 

of NOX as the total of all hourly 

emissions data for a glass manufacturing 

furnace in the preceding 30 days, 

divided by the total tons of glass 

produced in that furnace during the 

same 30-operating day period. Owners 

or operators of glass manufacturing 

furnaces installed with continuous 

emissions monitoring may demonstrate 

compliance with the emissions limit as 

follows: (1) Determine the average 

pounds of NOX emitted per day, (2) 

determine the tons of glass removed per 

day during the same day, (3) divide the 

average pounds of NOX emitted per day 

by the tons of glass removed per day as 

determined in step (2), and (4) compare 

the quotient to the emissions limits 

prescribed in the Section VII of this 

proposed rule. If the pollutant mass 

emissions rate is in lb/hr, the following 

equation 321 shall be used to convert the 

emissions rate to lb pollutant/ton of 

glass pulled: 


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. !:!!..emitted lb emitted I ton of glass pulled = hr . tons 

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20148 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

5. Boilers From Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills 

Applicability 

The EPA is proposing to establish 

regulatory requirements for the Basic 

Chemical Manufacturing, Petroleum and 

Coal Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills industries 

that apply to boilers within these 

facilities that have a design capacity of 

100 mmBtu/hr or greater. These 

requirements are consistent with EPA’s 

findings at Step 3 with respect to Tier 

2 non-EGU industries. As noted below, 

we do not believe boilers meeting this 

size classification exist within the other 

Tier 2, or Tier 1 industries, but if they 

do, the EPA proposes that they would 

also be subject to the requirements of 

this part. Based on our review of the 

potential emissions from industrial 

boilers of various fuel types, we find 

that use of a boiler design capacity of 

100 mmBtu/hr reasonably approximates 

the selection of 100 tpy used within the 

Non-EGU Screening Assessment 

memorandum. Therefore, boilers subject 

to the requirements of this section of the 

proposed rule are those found within 

any of the 23 covered states with nonEGU emissions reduction obligations 

that are within a Tier 1 or Tier 2 

industry and have a design capacity of 

100 mmBTU/hr or greater. The EPA is 

seeking comment on whether EPA 

should alternatively set an applicability 

threshold based on potential to emit. 

Emissions Limitations and Rationale 

This section of the proposed rule 

applies to certain boilers located at any 

facility identified as a Tier 2 industry 

within the non-EGU screening 

assessment. As described within the 

Non-EGU Screening Assessment 

memorandum, the EPA reviewed the 

projected 2026 emissions data to 

identify large boilers within the Tier 2 

industries, defined as boilers projected 

to emit more than 100 tons per year in 

2026. Boilers meeting this threshold 

were found in three of the five Tier 2 

industries, as identified in Table 

VII.C.5–1. 

TABLE VII.C.5–1—TIER 2 INDUSTRIES

WITH LARGE BOILERS AND ASSOCIATED NAICS CODES

Industry NAICS 

code 

Basic Chemical Manufacturing ......... 3251xx 

Petroleum and Coal Products Manufacturing ........................................ 3241xx 

Pulp, Paper, and Paperboard Mills .. 3221xx 

The EPA did not find large boilers 

within the Lime and Gypsum Product 

Manufacturing (NAICS code 3274xx) or 

the Metal Ore Mining industries (NAICS 

code 2122xx). As such the EPA is not 

expressly proposing to include boilers 

in those industries. However, if as a 

result of receiving additional 

information during the comment period 

the EPA identifies large boilers within 

these two industries that meet the 

applicability criteria described below, 

those boilers could be subject to the 

requirements of the final rule. 

As described within the Non-EGU 

Sectors TSD, the RACT rules we 

reviewed containing NOX limits for 

industrial boilers relied primarily on 

design capacity in mmBtu/hr as the 

metric for selecting design criteria. The 

EPA is proposing to use that same 

metric to establish control requirements 

for boilers with a design capacity of 100 

mmBtu/hr or greater. As noted within 

the Non-EGU Sectors TSD, boilers rated 

at 100 mmBtu/hr or greater can emit 

large amounts of NOX, particularly if 

they do not operate NOX control 

equipment. 

The EPA reviewed NOX emissions 

limits for industrial boilers with design 

capacities of 100 mmBtu/hr or greater 

that have been adopted by states and 

incorporated into their SIPs. The NonEGU Sectors TSD contains a detailed 

discussion of that evaluation. Based on 

our review, we propose to establish the 

following NOX emissions limits for coal, 

oil, and gas fired industrial boilers 

located at a Tier 2 industry: 

TABLE VII.C.5–2—PROPOSED NOX EMISSIONS LIMITS FOR INDUSTRIAL BOILERS >100 MMBTU/HR

Unit type Emissions limit 

(lbs NOX/mmBtu) Additional information 

Coal ............................... 0.20 Limits reviewed ranged from 0.08 to 1.0. Proposed limit will likely require a combination of combustion controls or post-combustion controls. 

Residual oil .................... 0.20 Limits reviewed ranged from 0.15 to 0.50. Proposed limit will likely require combustion controls. 

Distillate oil .................... 0.12 Limits reviewed ranged from 0.10 to 0.43. Proposed limit will likely require combustion controls. 

Natural gas .................... 0.08 Limits reviewed ranged from 0.06 to 0.25. 

Proposed limit will likely require a combination of combustion controls or post-combustion controls. 

Additional information on the EPA’s 

derivation of these proposed emissions 

rates for boilers is provided below and 

in the Non-EGU Sectors TSD. 

The EPA notes that some coal, oil, 

and gas-fired industrial boilers may 

have already installed combustion or 

post-combustion control equipment, 

such as SCR or SNCR, sufficient to meet 

the emission limits established in this 

FIP. Some of the boilers covered by this 

FIP might have install controls to meet 

the emission limits contained within 

EPA’s NSPS located at 40 CFR 60 

Subpart Db, which requires that some 

fossil fuel-fired units that commenced 

construction, modification, or 

reconstruction after June 19, 1984, meet 

various NOx emission limits based on 

factors such as unit type or heat rate. 

Additionally, industrial boilers located 

in ozone nonattainment areas or within 

the ozone transport region may have 

installed controls to meet emission 

limits adopted by states to meet NOx

RACT requirements. 

a. Coal-Fired Industrial Boilers 

Coal-fired industrial boilers subject to 

the proposed requirements of this 

section would have to meet a NOX

emissions limit of 0.2 lbs/mmBtu on a 

30-day rolling average basis. 

Various forms of combustion and 

post-combustion NOX control 

technology exist that should enable 

most facilities to be retrofit with 

equipment that will enable them to meet 

these emissions limits. Additionally, as 

noted in the Non-EGU Sectors TSD, 

many states containing ozone 

nonattainment areas or located within 

the OTR have already adopted 

emissions limits similar to or more 

stringent than the limits the EPA 

proposes here. Furthermore, some coalfired industrial boilers may have 

installed combustion or postcombustion control equipment to meet 

the emissions limits contained within 

EPA’s NSPS located at 40 CFR part 60 

subpart Db, which requires that coalfired industrial boilers meet a NOX

emissions limit of between 0.5 and 0.8 


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322 40 CFR 60.44b. 

323 ‘‘Alternative Control Techniques Document— 

NOX Emissions from Industrial/Commercial/ 

Institutional (ICI) Boilers,’’ EPA–453/R–94–022, 

March 1994. 

324For example, see ‘‘Applicability and 

Feasibility of NOX, SO2, and PM Emissions Control 

Technologies for Industrial, Commercial, and 

Institutional Boilers,’’ Northeast States for 

Coordinated Air Use Management, November 2008 

(revised January 2009) and ‘‘Nitrogen Oxides (NOx), 

Why and How They Are Controlled,’’ EPA, Clean 

Air Technical Center, 456/F–99–006R, November 

1999. 325 40 CFR 60.44b. 326CAA sections 110(c)(1)(B), 110(k)(3). 

lbs/mmBtu depending on unit type.322

Enhancements to or retrofit of 

additional NOX control technology 

should enable most sources to meet the 

proposed NOX limit. 

There are two main types of NOX

control technology that we believe can 

be retrofit to most existing industrial 

boilers, or incorporated into the design 

of new boilers, to meet our proposed 

emissions limits. These two control 

types are combustion controls and postcombustion controls, and in some 

instances both types are used together. 

As noted in the EPA’s ‘‘Alternative 

Control Techniques Document—NOX

Emissions from Industrial/Commercial/ 

Institutional (ICI) Boilers’’ (hereafter 

‘‘ICI Boiler ACT’’),323 the type of NOX

control available for use on a particular 

unit depends primarily on the type of 

boiler, fuel type, and fuel-firing 

configuration. For example, Table 2–3 of 

the ICI Boiler ACT indicates which 

types of combustion and postcombustion NOX controls are suitable to 

various types of coal-fired ICI boilers. 

We note that one type of combustion 

control, staged combustion air, and one 

type of post-combustion control, SNCR, 

are indicated as being compatible with 

all coal-fired unit types. Additional 

resources are available that document 

the availability of NOX control 

equipment for industrial boilers.324

b. Oil-Fired Industrial Boilers 

Most oil-fired boilers are fueled by 

either residual (heavy) oil or distillate 

(light) oil. The proposed NOX emissions 

limit for residual oil-fired boilers subject 

to the requirements of this section is 0.2 

lbs/mmBtu, and the proposed emissions 

limit for distillate oil-fired boilers is 

0.12 lbs/mmBtu. The proposed 

averaging time for these emissions 

limits is a 30-day rolling average. As 

with coal-fired industrial boilers, a 

number of combustion and postcombustion NOX control technologies 

exist that should enable most facilities 

to meet these emissions limits, and the 

Non-EGU Sectors TSD identifies 

numerous states that have already 

adopted emissions limits similar to the 

limits EPA proposes here. Table 2–3 of 

the ICI Boiler ACT indicates that two 

types of NOX combustion control, lowNOX burners and flue gas recirculation, 

are commonly found on oil-fueled 

industrial boilers, and that SNCR, a 

post-combustion control technology, is 

suitable to most oil-fueled industrial 

boilers other than those of the packaged 

firetube design. Some oil-fired 

industrial boilers may have already 

installed combustion or postcombustion control equipment to meet 

the emissions limits contained within 

EPA’s NSPS at 40 CFR part 60 subpart 

Db, which requires that distillate oilfired units meet a NOX emissions limit 

of between 0.1 to 0.2 lbs/mmBtu 

depending on heat release rate, and that 

residual oil-fired units meet a NOX

emissions limit of between 0.3 to 0.4 

lbs/mmBtu also depending on heat 

release rate.325 The additional resources 

noted in the paragraph above discussing 

coal-fired industrial boilers also contain 

useful information regarding effective 

NOX control equipment for residual and 

distillate fueled industrial boilers. 

c. Gas-Fired Industrial Boilers 

The proposed NOX emissions limit for 

gas-fired boilers subject to the 

requirements of this section is 0.08 lbs/ 

mmBtu. The proposed averaging time 

for these emissions limits is a 30-day 

rolling average. 

As with fossil-fuel-fired boilers, 

numerous combustion and postcombustion NOX control technologies 

exist that should enable most facilities 

to meet these emissions limits, and 

many states have already adopted 

emissions limits similar to the limits the 

EPA proposes here. Table 2–3 of the ICI 

Boiler ACT indicates the same control 

technologies that are suitable for 

application to oil-fired boilers are also 

likely to be effective at controlling NOX

emissions from gas-fired industrial 

boilers. Some gas-fired industrial boilers 

may have already installed combustion 

or post-combustion control equipment 

to meet the emissions limits contained 

within EPA’s NSPS at 40 CFR 60 

Subpart Db, which requires that gasfired units meet a NOX emissions limit 

of between 0.1 to 0.2 lbs/MMBtu 

depending on heat release rate. The 

additional resources noted in the 

discussion of coal-fired industrial 

boilers also contain useful information 

regarding effective NOX control 

equipment for gas-fired industrial 

boilers. 

The EPA anticipates that the majority 

of boilers covered by this section of the 

FIP will combust one of the fuels for 

which we have proposed emissions 

limits. However, we request comment 

on whether emissions limits for other 

types of fuels should be included in a 

final FIP, and if so, the types of fuels 

and the emissions limits that boilers 

powered by these fuels should be 

required to meet. Additionally, the EPA 

seeks comment on whether the EPA 

should establish less stringent emissions 

rates for boilers with low utilization 

rates, and if so, the appropriate 

emissions rate(s) and corresponding 

boiler utilization rate(s). The EPA also 

seeks comment on whether a different 

averaging time other than the 30-day 

averaging time proposed for boilers 

would be more appropriate and requests 

information supporting any suggested 

alternative. 

Compliance Assurance Requirements 

Given the similarities in the types of 

units covered, the EPA proposes that 

boilers subject to the requirements of 

this section demonstrate compliance in 

a manner similar to the emissions 

monitoring requirements found in 

section 60.45 of the NSPS for industrial, 

commercial, and institutional (ICI) 

boilers at 40 CFR part 60 subpart D. 

Those requirements include, among 

other provisions, the performance of an 

initial compliance test, installation of a 

CEMS unless the initial performance 

test indicates the unit’s emissions rate is 

70 percent or less of the required 

emissions rate, and an annual stack test 

for units not required to install a CEMS. 

D. Submitting a SIP 

A state may submit a SIP at any time 

to address CAA requirements that are 

covered by a FIP, and if the EPA 

approves the SIP it would replace the 

FIP, in whole or in part, as 

appropriate.326 The EPA has established 

certain specialized provisions for 

replacing FIPs with SIPs within all the 

CSAPR trading programs, including the 

use of so-called ‘‘abbreviated SIPs’’ and 

‘‘full SIPs,’’ see 40 CFR 52.38(a)(4) and 

(5) and (b)(4), (5), (8), (9), (11), and (12); 

40 CFR 52.39(e), (f), (h), and (i). For a 

state to remove all FIP provisions 

through an approved SIP revision, a 

state would need to address all of the 

required reductions addressed by the 

FIP for that state, i.e., reductions 

achieved through both EGU control and 

non-EGU control, as applicable to that 

state. Additionally, tribes in Indian 

country within the geographic scope of 

this proposed rule may elect to work 

with EPA under the Tribal Authority 

Rule to replace the FIP for areas of 

Indian country, in whole or in part, with 

a tribal implementation plan or 


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reasonably severable portions of a tribal 

implementation plan. 

Under the proposed new FIPs for the 

25 states whose EGUs would be 

required to participate in the CSAPR 

NOX Ozone Season Group 3 Trading 

Program with its proposed 

modifications, ‘‘abbreviated’’ and ‘‘full’’ 

SIP options continue to be available. An 

‘‘abbreviated SIP’’ allows a state to 

submit a SIP revision that would 

establish state-determined allowance 

allocation provisions replacing the 

default FIP allocation provisions but 

leaves the remaining FIP provisions in 

place. A ‘‘full SIP’’ allows a state to 

adopt a trading program meeting certain 

requirements that would allow sources 

in the state to continue to use the EPAadministered trading program through 

an approved SIP revision, rather than a 

FIP. In addition, as under past CSAPR 

rulemakings, the EPA proposes to 

provide states with an opportunity to 

adopt state-determined allowance 

allocations for existing units for the 

second control period under this rule— 

in this case, the 2024 control period— 

through streamlined SIP revisions. See 

76 FR 48326–48332 for additional 

discussion of full and abbreviated SIP 

options; see also 40 CFR 52.38(b). 

1. SIP Option To Modify Allocations for 

2024 Under EGU Trading Program 

As with the start of past CSAPR 

rulemakings, the EPA proposes to allow 

a state to use a similar process to submit 

a SIP revision establishing allowance 

allocations for existing EGU units in the 

state for the second control period of the 

new requirements, i.e., in 2024, to 

replace the EPA-determined default 

allocations. This proposed process 

would use updated deadlines, i.e., a 

state must submit a letter to EPA within 

60 days of publication of the final rule 

indicating its intent to submit a 

complete SIP revision by September 1, 

2023. The SIP would provide in an EPAprescribed format a list of existing units 

within the state and their allocations for 

the 2024 control period. If a state does 

not submit a letter of intent to submit 

a SIP revision, the EPA-determined 

default allocations will be recorded by 

90 days of publication of the final rule. 

If a state submits a timely letter of intent 

but fails to submit a SIP revision, the 

EPA-determined default allocations will 

be recorded by September 15, 2023. If a 

state submits a timely letter of intent 

followed by a timely SIP revision that is 

approved, the approved SIP allocations 

will be recorded by March 1, 2024. 

The EPA requests comment on the 

proposed option to modify allowance 

allocations under the Group 3 trading 

program for EGUs for the 2024 control 

period through a SIP revision. 

2. SIP Option To Modify Allocations for 

2025 and Beyond Under EGU Trading 

Program 

For the 2025 control period and later, 

the EPA proposes that states in the 

CSAPR NOX Ozone Season Group 3 

Trading Program can modify the EPAdetermined default allocations with an 

approved SIP revision. For the 2025 

control period and later, SIPs can be full 

or abbreviated SIPs. States will also 

have the option to expand applicability 

to include EGUs between 15 MWe and 

25 MWe or, in the case of states subject 

to the NOX SIP Call, as discussed in 

Section VII.F.1 of this proposed rule, 

large non-EGU boilers and combustion 

turbines. Inclusion of the large nonEGUs would serve as a mechanism to 

address the state’s outstanding 

regulatory obligations under the NOX

SIP Call with respect to those sources, 

and the state would be allowed to 

allocate a defined quantity of additional 

Group 3 allowances because of the 

expanded set of sources. See above and 

76 FR 48326–48332 for additional 

discussion of full and abbreviated SIP 

options; see also 40 CFR 52.38(b). 

For states that want to modify the 

EPA-determined default allocations or 

expand applicability of the EGU trading 

program, the EPA proposes that a state 

could submit a SIP revision that makes 

changes only to one or both of those 

type of provisions while relying on the 

FIP for the remaining provisions of the 

EGU trading program. This abbreviated 

SIP option allows states to tailor the FIP 

to their individual choices while 

maintaining the FIP-based structure of 

the trading program. In order to ensure 

the availability of allowance allocations 

for units in any Indian country within 

a state not covered by the state’s CAA 

implementation planning authority, if 

the state chose to replace EPA’s default 

allocations with state-determined 

allocations, the EPA would continue to 

administer any portion of each state 

emissions budget reserved as a new unit 

set-aside or an Indian country existing 

unit set-aside. 

The proposed SIP submittal deadline 

for this type of revision is December 1, 

2023, if the state intends for the SIP 

revision to be effective beginning with 

the 2025 control period. For states that 

submit this type of SIP revision, the 

EPA proposes that the deadline to 

submit state-determined allocations 

beginning with the 2025 control period 

under an approved SIP would be June 

1, 2024, and the deadline for the EPA 

to record those allocations would be 

July 1, 2024. Similarly, under the 

proposed new deadlines a state could 

submit a SIP revision beginning with 

the 2026 control period and beyond by 

December 1, 2024, with state allocations 

for the 2026 control period due June 1, 

2025, and the EPA recordation of the 

allocations by July 1, 2025. 

The EPA requests comment on the 

proposed option to replace certain 

allowance allocation or applicability 

provisions under the Group 3 trading 

program for EGUs for control periods in 

2025 and later years through a SIP 

revision. 

3. SIP Option To Replace the Federal 

EGU Trading Program With an 

Integrated State EGU Trading Program 

For the 2025 control period and later, 

the EPA proposes that states in the 

CSAPR NOX Ozone Season Group 3 

Trading Program can choose to replace 

the Federal EGU trading program with 

an integrated State EGU trading program 

through an approved SIP revision. 

Under this option, a state would submit 

a SIP revision that makes changes only 

to modify the EPA-determined default 

allocations or expand applicability of 

the EGU trading program and adopt 

identical provisions for the remaining 

portions of the EGU trading program. 

This SIP option allows states to replace 

these FIP provisions with state-based 

SIP provisions while continuing 

participation in the larger regional 

trading program. As with the 

abbreviated SIP option discussed above, 

in order to ensure the availability of 

allowance allocations for units in any 

Indian country within a state not 

covered by the state’s CAA 

implementation planning authority, if 

the state chose to replace EPA’s default 

allocations with state-determined 

allocations, EPA would continue to 

administer any portion of each state 

emissions budget reserved as a new unit 

set-aside or an Indian country existing 

unit set-aside. 

Proposed deadlines for this type of 

SIP revision are the same as the 

deadlines for abbreviated SIP revisions. 

For the SIP-based program to start with 

the 2025 control period, the SIP 

deadline would be December 1, 2023, 

the deadline to submit state-determined 

allocations for the 2025 control period 

under an approved SIP would be June 

1, 2024, and the deadline for the EPA 

to record those allocations would be 

July 1, 2024, and so on. 

The EPA requests comment on the 

proposed option to replace the federal 

trading program for EGUs with an 

integrated state trading program for 

EGUs for control periods in 2025 and 

later years through a SIP revision. 


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327Part 70 addresses requirements for state title 

V programs, and Part 71 governs the federal title V 

program. 

4. SIP Revisions That Do Not Use the 

New Trading Program 

States can submit SIP revisions to 

replace the FIP that achieve the 

necessary EGU emissions reductions but 

do not use the CSAPR NOX Ozone 

Season Group 3 Trading Program. For a 

transport SIP revision that does not use 

the CSAPR NOX Ozone Season Group 3 

Trading Program, the EPA would 

evaluate the transport SIP based on the 

particular control strategies selected and 

whether the strategies as a whole 

provide adequate and enforceable 

provisions ensuring that the necessary 

emissions reductions (i.e., reductions 

equal to or greater than what the Group 

3 trading program will achieve) will be 

achieved. In order to address the 

applicable CAA requirements, the SIP 

revision should include the following 

general elements: (1) A comprehensive 

baseline 2023 statewide NOX emissions 

inventory (which includes existing 

control requirements), which should be 

consistent with the 2023 emissions 

inventory that the EPA used to calculate 

the required state budget in this final 

proposed rule (unless the state can 

explain the discrepancy); (2) a list and 

description of control measures to 

satisfy the state emissions reduction 

obligation and a demonstration showing 

when each measure would be 

implemented to meet the 2023 and 

successive control periods; (3) fullyadopted state rules providing for such 

NOX controls during the ozone season; 

(4) for EGUs greater than 25 MWe, 

monitoring and reporting under 40 CFR 

part 75, and for other units, monitoring 

and reporting procedures sufficient to 

demonstrate that sources are complying 

with the SIP (see 40 CFR part 51 subpart 

K (‘‘source surveillance’’ requirements)); 

and (5) a projected inventory 

demonstrating that state measures along 

with federal measures will achieve the 

necessary emissions reductions in time 

to meet the 2023 and successive 

compliance deadlines (e.g., enforceable 

reductions commensurate with 

installation of SCR on coal-fired EGUs 

by the 2026 ozone season). The SIPs 

must meet procedural requirements 

under the Act, such as the requirements 

for public hearing, be adopted by the 

appropriate state board or authority, and 

establish by a practically enforceable 

regulation or permit(s) a schedule and 

date for each affected source or source 

category to achieve compliance. Once 

the state has made a SIP submission, the 

EPA will evaluate the submission(s) for 

completeness before acting on the SIP. 

EPA’s criteria for determining 

completeness of a SIP submission are 

codified at 40 CFR part 51 appendix V. 

For further information on replacing a 

FIP with a SIP, see the discussion in the 

final CSAPR rulemaking (76 FR 48326). 

5. SIP Revision Requirements for NonEGU Emissions Limits 

EPA’s promulgation of a non-EGU 

transport FIP would in no way affect the 

ability of states to submit, for review 

and approval, a SIP that replaces the 

requirements of the FIP with state 

requirements. In order to replace the 

non-EGU portion of the FIP in a state, 

the state’s SIP must provide adequate 

provisions to prohibit an equivalent or 

greater amount of NOX emissions that 

contribute significantly to 

nonattainment or interfere with 

maintenance of the 2015 ozone NAAQS 

in any other state. The non-EGU 

requirements of the FIP would remain 

in place in each covered state until a 

state’s SIP has been approved by the 

EPA to replace the FIP. 

After promulgation of the final FIP, 

the EPA anticipates that the most 

straightforward method for a state to 

submit a SIP revision to replace the nonEGU portion of the FIP for the state 

would be to provide a SIP that includes 

emissions limits at an equivalent or 

greater level of stringency than is 

specified for non-EGU sources meeting 

the applicability criteria and associated 

compliance assurance provisions for 

each of the unit types identified in 

Section VII.C of this proposed rule. 

The EPA seeks comment on other 

potential methods by which states could 

develop a SIP to obtain emissions 

reductions from non-EGU sources that 

would replace the state’s non-EGU 

portion of the FIP. The EPA recognizes 

that states may select emissions 

reductions strategies that differ from the 

emissions limitations included in the 

proposed non-EGU FIP. But the state 

must still demonstrate that the 

replacement SIP provides an equivalent 

or greater amount of emissions 

reductions as the proposed FIP. The 

EPA anticipates that such emissions 

reductions strategies would have to 

achieve reductions beyond those 

emissions reductions already projected 

to occur in EPA’s emissions projections 

and air quality modeling conducted at 

Steps 1 and 2. Such reductions must 

also be achieved on the same timeframe 

as the reductions that would be required 

in a final FIP. A demonstration of 

equivalency using other control 

strategies is complicated by the fact that 

the proposed emissions limits for nonEGU sources are generally rate-based 

and expressed in a variety of forms; this 

will make comparative analysis to 

determine equivalency challenging. 

In all cases, a SIP submitted by a state 

to replace the non-EGU FIPs would 

need to rely on permanent and 

practically enforceable controls 

measures that are included in the SIP 

and, once approved by the EPA, 

rendered federally enforceable. Socalled ‘‘demonstration-only’’ or ‘‘nonregulatory’’ SIPs would be insufficient. 

Further, the EPA anticipates that states 

would bear the burden of establishing 

that the state’s alternative approach 

achieves at least an equivalent level of 

emissions reduction as the FIP, and 

(unless merely adopting directly the 

control requirements of the FIP) the 

state would need to provide a Step 3 

multifactor analysis that the state’s SIP 

eliminates significant contribution. 

E. Title V Permitting 

This proposed rule, like CSAPR, the 

CSAPR Update, and the Revised CSAPR 

Update does not establish any 

permitting requirements independent of 

those under Title V of the CAA and the 

regulations implementing Title V, 40 

CFR parts 70 and 71.327 All major 

stationary sources of air pollution and 

certain other sources are required to 

apply for title V operating permits that 

include emissions limitations and other 

conditions as necessary to ensure 

compliance with the applicable 

requirements of the CAA, including the 

requirements of the applicable SIP. CAA 

sections 502(a) and 504(a), 42 U.S.C. 

7661a(a) and 7661c(a). The ‘‘applicable 

requirements’’ that must be addressed in 

title V permits are defined in the title V 

regulations (40 CFR 70.2 and 71.2 

(definition of ‘‘applicable 

requirement’’)). 

The EPA anticipates that, given the 

nature of the units subject to this 

proposed rule, most if not all of the 

sources at which the units are located 

are already subject to title V permitting 

requirements. For sources subject to title 

V, the interstate transport requirements 

for the 2015 ozone NAAQS that are 

applicable to them under the new or 

amended FIPs would be ‘‘applicable 

requirements’’ under title V and 

therefore must be addressed in the title 

V permits. For example, requirements 

concerning designated representatives, 

monitoring, reporting, and 

recordkeeping, the requirement to hold 

allowances covering emissions, the 

compliance assurance provisions, and 

liability are ‘‘applicable requirements’’ 

that must be addressed in the permits. 

Title V of the CAA establishes the 

basic requirements for state title V 


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328The 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. 

329 Id. 

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

petition-responses. 

331A 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). 

permitting programs, including, among 

other things, provisions governing 

permit applications, permit content, and 

permit revisions that address applicable 

requirements under final FIPs in a 

manner that provides the flexibility 

necessary to implement market-based 

programs such as the trading programs 

established in CSAPR, the CSAPR 

Update, the Revised CSAPR Update and 

this proposed rule. 42 U.S.C. 7661a(b); 

40 CFR 70.6(a)(8) & (10); 40 CFR 

71.6(a)(8) & (10). 

In CSAPR, the CSAPR Update and the 

Revised CSAPR Update, the EPA 

established standard requirements 

governing how sources covered by that 

rule would comply with title V and its 

regulations.328 40 CFR 97.506(d), 

97.806(d) and 97.1006(d). For any new 

or existing sources subject to this 

proposed rule, identical title V 

compliance provisions would apply, 

just as they would have in the CSAPR 

NOX Ozone Season Group 3 Trading 

Program. For example, the title V 

regulations provide that a permit issued 

under title V must include ‘‘[a] 

provision stating that no permit revision 

shall be required under any approved 

. . . emissions trading and other similar 

programs or processes for changes that 

are provided for in the permit.’’ 40 CFR 

70.6(a)(8) and 71.6(a)(8). Consistent 

with these provisions in the title V 

regulations, in CSAPR, the CSAPR 

Update and the Revised CSAPR Update, 

the EPA included a provision stating 

that no permit revision is necessary for 

the allocation, holding, deduction, or 

transfer of allowances. 40 CFR 

97.506(d)(1), 97.806(d)(1) and 

97.1006(d)(1). This provision is also 

included in each title V permit for an 

affected source. This proposed rule 

maintains the approach taken under 

CSAPR, the CSAPR Update and the 

Revised CSAPR Update that allows 

allowances to be traded (or allocated, 

held, or deducted) without a revision to 

the title V permit of any of the sources 

involved. 

Similarly, this proposed rule would 

also continue to support the means by 

which a source in the proposed trading 

program can use the title V minor 

modification procedure to change its 

approach for monitoring and reporting 

emissions, in certain circumstances. 

Specifically, sources may use the minor 

modification procedure so long as the 

new monitoring and reporting approach 

is one of the prior-approved approaches 

under CSAPR, the CSAPR Update and 

the Revised CSAPR Update (i.e., 

approaches using a continuous 

emissions monitoring system under 

subparts B and H of part 75, an excepted 

monitoring system under appendices D 

and E to part 75, a low mass emissions 

excepted monitoring methodology 

under 40 CFR 75.19, or an alternative 

monitoring system under subpart E of 

part 75), and the permit already 

includes a description of the new 

monitoring and reporting approach to be 

used. See 40 CFR 97.506(d)(2), 

97.806(d)(2) and 97.1006(d)(2); 40 CFR 

70.7(e)(2)(i)(B) and 40 CFR 

71.7(e)(1)(i)(B). As described in EPA’s 

2015 Title V Guidance, sources may 

comply with this requirement by 

including a table of all of the approved 

monitoring and reporting approaches 

under CSAPR, the CSAPR Update and 

the Revised CSAPR Update trading 

programs in which the source is 

required to participate, and the 

applicable requirements governing each 

of those approaches.329 Inclusion of 

such a table in a source’s title V permit 

therefore allows a covered unit that 

seeks to change or add to its chosen 

monitoring and recordkeeping approach 

to easily comply with the regulations 

governing the use of the title V minor 

modification procedure. 

Under CSAPR, the CSAPR Update 

and the Revised CSAPR Update, in 

order to employ a monitoring or 

reporting approach different from the 

prior-approved approaches discussed 

previously, unit owners and operators 

must submit monitoring system 

certification applications to the EPA 

establishing the monitoring and 

reporting approach actually to be used 

by the unit, or, if the owners and 

operators choose to employ an 

alternative monitoring system, to submit 

petitions for that alternative to the EPA. 

These applications and petitions are 

subject to the EPA review and approval 

to ensure consistency in monitoring and 

reporting among all trading program 

participants. EPA’s responses to any 

petitions for alternative monitoring 

systems or for alternatives to specific 

monitoring or reporting requirements 

are posted on EPA’s website.330 The 

EPA maintains the same approach in 

this proposed rule. 

Consistent with EPA’s approach 

under CSAPR, the CSAPR Update and 

the Revised CSAPR Update, the 

applicable requirements resulting from 

the new and amended FIPs generally 

will have to be incorporated into 

affected sources’ existing title V permits 

either pursuant to the provisions for 

reopening for cause (40 CFR 70.7(f) and 

71.7(f)) or the standard permit renewal 

provisions (40 CFR 70.7(c) and 

71.7(c)).331 For sources newly subject to 

title V that are affected sources under 

the FIPs, the initial title V permit issued 

pursuant to 40 CFR 70.7(a) should 

address the final FIP requirements. 

As was the case in the CSAPR, the 

CSAPR Update and the Revised CSAPR 

Update, the new and amended FIPs 

impose no independent permitting 

requirements and the title V permitting 

process will impose no additional 

burden on sources already required to 

be permitted under title V. 

F. Relationship to Other Emissions

Trading and Ozone Transport Programs

1. NOX SIP Call

States affected by both the NOX SIP

Call for the 1979 ozone NAAQS and any 

final ozone season requirements 

established upon finalization of this 

proposed rule for the 2015 ozone 

NAAQS will be required to comply with 

the requirements of both rules. EPA is 

proposing to require NOX ozone season 

emissions reductions from EGUs larger 

than 25 MWe in many of the NOX SIP 

Call states, and at greater stringency 

than required by the NOX SIP Call, by 

requiring the EGUs to participate in the 

CSAPR NOX Ozone Season Group 3 

Trading Program. Therefore, this 

proposed rule, if finalized, would satisfy 

the requirements of the NOX SIP Call for 

these large EGUs. 

In the Revised CSAPR Update, the 

EPA finalized the option for any NOX

SIP Call state that was also subject to the 

Revised CSAPR Update to voluntarily 

submit a SIP revision to expand the 

applicability of the Group 3 trading 

program to include all NOX Budget 

Trading Program units, which in 

addition to large EGUs also include 

large non-EGU boilers and combustion 

turbines with a maximum design heat 

input greater than 250 mmBtu/hr. As 

part of such a SIP revision, the state 


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332 In the CSAPR Update, the EPA finalized an 

identical option allowing NOX SIP Call states to 

expand applicability of the Group 2 trading 

program to cover certain non-EGUs. If the 

geographic expansion of the Group 3 trading 

program proposed in this rulemaking is finalized as 

proposed, no NOX SIP Call states would continue 

to be covered by the Group 2 trading program. 

Because the provision allowing NOX SIP Call states 

to expand applicability of the Group 2 trading 

program to include such non-EGUs would therefore 

be obsolete, the EPA is proposing to remove the 

provision. 

333 59 FR 7629, February 16, 1994. 

334 86 FR 7009, January 20, 2021. 

335https://www.epa.gov/environmentaljustice. 

336U.S. Environmental Protection Agency (EPA), 

2015. Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. 

337The 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). 

would be allowed to issue additional 

emissions allowances capped at a level 

intended to preserve the stringency of 

the Group 3 trading program. In today’s 

proposed rule, the EPA is not proposing 

any changes to this provision of the 

Group 3 trading program.332

2. Acid Rain Program 

This proposed rule, if finalized, 

would not affect any Acid Rain Program 

requirements. Any Title IV sources that 

are subject to provisions of this 

proposed rule would still need to 

continue to comply with all Acid Rain 

provisions. Acid Rain Program SO2 and 

NOX requirements are established 

independently in Title IV of the CAA 

and will continue to apply 

independently of this proposed rule’s 

provisions. Acid Rain sources will still 

be required to comply with Title IV 

requirements, including the requirement 

to hold Title IV allowances to cover SO2

emissions after the end of a compliance 

year. 

3. Other Current Emissions Trading 

Programs 

This proposed rule, if finalized, 

would not substantively affect any 

provisions of the CSAPR NOX Annual, 

CSAPR SO2 Group 1, CSAPR SO2 Group 

2, CSAPR NOX Ozone Season Group 1, 

or CSAPR NOX Ozone Season Group 2 

trading programs for sources that 

continue to participate in those 

programs except with regard to the 

schedule for EPA to record certain 

allowance allocations, as discussed in 

Section VII.B.12 of this proposed rule. 

In addition, certain revisions are 

proposed to the CSAPR NOX Ozone 

Season Group 2 Trading Program 

regulations to address the proposed 

transition of sources in eight states from 

that program to the CSAPR NOX Ozone 

Season Group 3 Trading Program, as 

discussed in Section VII.B.11 of this 

proposed rule. Sources that are subject 

to any of the CSAPR trading programs 

will still be required to comply with all 

requirements, including the requirement 

to hold allowances to cover emissions 

after the end of a control period. 

VIII. Environmental Justice Analytical 

Considerations and Stakeholder 

Outreach and Engagement 

Consistent with EPA’s commitment to 

integrating environmental justice in the 

agency’s actions, and following the 

directives set forth in multiple 

Executive Orders, the Agency has 

analyzed the impacts of this proposed 

rule on communities with 

environmental justice concerns and 

engaged with stakeholders representing 

these communities to seek input and 

feedback. Executive Order 12898 is 

discussed in Section XI.J of this 

proposed rule and analytical results are 

available in Chapter 7 of the RIA. 

A. Introduction 

Executive Order 12898 directs EPA 

staff to identify the populations of 

concern who are most likely to 

experience unequal burdens from 

environmental harms; specifically, 

minority populations, low-income 

populations, and indigenous peoples.333

Additionally, Executive Order 13985 is 

intended to advance racial equity and 

support underserved communities 

through federal government actions.334

The EPA defines environmental justice 

as the fair treatment and meaningful 

involvement of all people regardless of 

race, color, national origin, or income, 

with respect to the development, 

implementation, and enforcement of 

environmental laws, regulations, and 

policies. EPA further defines the term 

fair treatment to mean that ‘‘no group of 

people should bear a disproportionate 

burden of environmental harms and 

risks, including those resulting from the 

negative environmental consequences of 

industrial, governmental, and 

commercial operations or programs and 

policies.’’ 335 In recognizing that 

minority and low-income populations 

often bear an unequal burden of 

environmental harms and risks, EPA 

continues to consider ways of protecting 

them from adverse public health and 

environmental effects of air pollution. 

B. Analytical Considerations 

EPA’s environmental justice technical 

guidance 336 states that ‘‘[t]he analysis of 

potential EJ concerns for regulatory 

actions should address three questions: 

1. Are there potential environmental 

justice concerns associated with 

environmental stressors affected by the 

regulatory action for population groups of 

concern in the baseline? 

2. Are there potential environmental 

justice concerns associated with 

environmental stressors affected by the 

regulatory action for population groups of 

concern for the regulatory option(s) under 

consideration? 

3. For the regulatory option(s) under 

consideration, are potential environmental 

justice concerns created or mitigated 

compared to the baseline?’’ 

To address these questions in EPA’s 

first quantitative EJ analysis in the 

context of a transport rule, the EPA 

developed a unique analytical approach 

that considers the purpose and specifics 

of the proposed rulemaking, as well as 

the nature of known and potential 

exposures and impacts. However, due to 

data limitations, it is possible that our 

analysis failed to identify disparities 

that may exist, such as potential 

environmental justice characteristics 

(e.g., unemployed), environmental 

impacts (e.g., other ozone metrics), and 

more granular spatial resolutions (e.g., 

neighborhood scale) that were not 

evaluated. 

For the proposed rule, we employ two 

types of analytics to respond to the 

above three questions: Proximity 

analyses and exposure analyses. Both 

types of analyses can inform whether 

there are potential EJ concerns for 

population groups of concern in the 

baseline (question 1).337 In contrast, 

only the exposure analyses, which are 

based on future air quality modeling, 

can inform whether there will be 

potential EJ concerns after 

implementation of the regulatory 

options under consideration (question 

2) and whether potential EJ concerns 

will be created or mitigated compared to 

the baseline (question 3). While the 

exposure analysis can respond to all 

three questions, it should be noted that 

exposure is limited to a single ozone 

metric, the maximum daily 8-hour 

average, averaged across the April 

through September warm season (AS– 

MO3). This ozone metric likely smooths 

potential daily ozone gradients and is 

not directly relatable to the National 

Ambient Air Quality Standard 

(NAAQS). Additionally, the ozone 

exposure analytic results are provided 

in two formats: Aggregated and 

distributional. The aggregated results 

provide an overview of potential ozone 

exposure differences across populations 

at the national- and state-levels, while 

the distributional results show detailed 


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338This does not constitute EPA’s tribal 

consultation under E.O. 13175, which is described 

in Section XI.F of this proposed rule. 

information about ozone concentrations 

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 7.3.1), (2) the 

potential for disproportionate total 

ozone concentrations in the baseline 

across different demographic groups 

(Sections 7.4.1.1 and 7.4.2.1), and (3) 

how regulatory alternatives 

differentially impact the ozone 

concentration changes experienced by 

different demographic populations 

(Sections 7.4.1.2 and 7.4.2.2). Each of 

these analyses depends on mutually 

exclusive assumptions, was performed 

to answer separate questions, and is 

associated with unique limitations and 

uncertainties. 

Baseline demographic proximity 

analyses can be relevant for identifying 

populations that may be exposed to 

local pollutants, such as NO2 emitted 

from affected sources in this proposed 

rule. However, such analyses are less 

useful here as they do not account for 

the potential impacts of this proposed 

rule on long-range ozone concentration 

changes. The baseline demographic 

proximity analysis presented in the RIA 

finds larger percentages of Hispanic 

individuals, Black individuals, people 

below the poverty level, people with 

less educational attainment, and people 

linguistically isolated living within 5 

km and 10 km of an affected EGU, 

compared to national averages. It also 

finds larger percentages of people below 

the poverty level and with less 

educational attainment living within 5 

km and 10 km of an affected non-EGU. 

Separately, the tribal proximity analysis 

finds multiple tribes and unique tribal 

lands located within 50 miles of an 

affected facility. These results do not in 

themselves demonstrate 

disproportionate impacts of affected 

facilities in the baseline but could 

suggest that emission reductions from 

this proposed rule may be responsive to 

potential local air quality concerns of 

nearby communities. 

Whereas the proximity analyses are 

limited to evaluating local pollutants 

under baseline scenarios (question 1), 

the ozone exposure analyses can 

provide insight into all three EJ 

questions with regard to AS–MO3 

concentrations. Even though both the 

proximity and ozone exposure analyses 

can improve understanding of baseline 

EJ concerns (question 1), the two should 

not be directly compared. This is 

because the demographic proximity 

analysis does not include air quality 

information and is based on current, not 

future, population information. 

Importantly, the baseline analysis of 

AS–MO3 ozone concentrations 

responds to question 1 from EPA’s 

environmental justice technical 

guidance document more directly than 

the proximity analyses, as it evaluates a 

form of the environmental stressor 

targeted by the regulatory action. 

Baseline AS–MO3 analyses show that 

certain populations, such as American 

Indians, Hispanics, and Asians, may 

experience somewhat higher AS–MO3 

concentrations compared to the national 

average. The less educated and children 

may also experience higher 

concentrations compared to the national 

average, but to a lesser extent. 

Conversely, Black populations may 

experience lower AS–MO3 

concentrations than the national 

average. Therefore, also in response to 

question 1, there likely are potential 

environmental justice concerns 

associated with ozone exposures 

affected by the regulatory action for 

population groups of concern in the 

baseline. However, these baseline 

exposure results have not been fully 

explored and additional analyses are 

likely needed to understand potential 

implications. 

The ozone exposure analysis 

evaluates the impacts of the proposed 

rule on future ozone concentrations 

after rule implementation. When 

comparing across the policy, more-, and 

less-stringent regulatory alternatives, 

AS–MO3 concentrations are reduced 

across all populations evaluated in both 

future years and across both EGUs and 

non-EGUs. In other words, we expect 

that populations experiencing 

disproportionate AS–MO3 exposures in 

the baseline will experience similar 

disproportionate AS–MO3 exposures 

under the proposed rulemaking, 

although to a lesser absolute extent as 

the action described in this proposed 

rule is expected to lower ozone in many 

areas, including residual ozone 

nonattainment areas, and thus alleviate 

some pre-existing health risks of ozone 

across all populations evaluated. 

Therefore, in response to question 2, we 

expect that there will be potential EJ 

concerns with regard to AS–MO3 

concentrations after implementation of 

the regulatory options under 

consideration. 

Question 3 asks whether potential EJ 

concerns will be created or mitigated as 

compared to the baseline. As the RIA 

estimates disproportionate AS–MO3 

exposures in the baseline and similar 

reductions in all population evaluated, 

we do not predict that potential EJ 

concerns related to AS–MO3 

concentrations will be created or 

mitigated as compared to the baseline 

(question 3). 

The ozone exposure results should 

not be extrapolated to ozone metrics 

other than AS–MO3. Detailed 

environmental justice analytical results 

can be found in Chapter 7 of the RIA. 

C. Outreach and Engagement 

Prior to this proposed rule, EPA 

initiated a public outreach effort to 

gather input from stakeholder groups 

likely to be interested in this proposed 

rule. Specifically, the EPA hosted an 

environmental justice webinar on 

October 26, 2021, to share information 

about the proposed rule and solicit 

feedback about potential environmental 

justice considerations. The webinar was 

attended by over 180 individuals 

representing state governments, 

federally recognized tribes, 

environmental NGOs, higher education 

institutions, industry, and the EPA.338

Participants were invited to comment 

during the webinar or provide written 

comments to a pre-regulatory docket. 

The webinar was recorded and 

distributed to attendees after the event. 

Some of the key issues raised by 

stakeholders during the webinar and in 

the pre-proposal comments are 

described below. 

Daily emissions rate limits. Several 

commenters asserted that cap and trade 

programs with seasonal limits on overall 

NOX emissions do not prevent facilities 

from running their controls inefficiently 

on high ozone days. These commenters 

recommended that facilities linked to 

downwind ozone problems comply with 

daily rate limits to ensure that emissions 

reductions occur on days when ozone is 

highest. The commenters noted that 

daily limits could particularly benefit 

environmental justice communities 

located near facilities and would also 

benefit those located downwind. 

Regulation of other sources. Several 

commenters asserted that the EPA 

should consider regulation of sources 

other than EGUs and sources of NOX in 

rulemakings pertaining to issues of 

ozone transport. For example, some 

commenters asserted that the EPA 

should regulate emissions from nonEGUs, mobile sources, and sources of 

VOCs. 

Environmental justice analysis and 

methodology in rulemakings. Several 

commenters offered recommendations 

to improve environmental justice 

analysis and methodology in 

rulemakings that address air pollution. 


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One commenter recommended that the 

EPA should broadly: (1) Identify 

communities of interest, based on the 

number of and proximity to polluting 

facilities; (2) integrate demographic 

factors to discern social, economic, and 

racial disparities in these areas; (3) 

consider the community’s particular 

vulnerabilities and sensitivities to 

health harms and risks, and exposure to 

cumulative health harms and risks; and 

(4) reach out to the community members 

near such facilities themselves to gain 

tangible, lived experiences across their 

lifetimes. The commenter also suggested 

that the EPA should build off factors 

identified in existing environmental 

justice screening tools, including EPA 

EJSCREEN and California’s 

CalEnviroScreen. One commenter noted 

that in developing environmental justice 

analyses, the EPA should consider and 

address the need for regulatory 

certainty, including the need for clear 

regulatory definitions of environmental 

justice areas and clear requirements for 

those areas. 

Environmental justice stakeholder 

outreach in rulemakings. Some 

commenters asserted that the EPA could 

improve stakeholder outreach in the 

rulemaking process. For example, one 

commenter noted that during the 

development of a rule proposal, the EPA 

could more directly reach out to all 

potentially impacted environmental 

justice communities, be more prepared 

to answer questions about the rule 

proposal, and be more aware of holidays 

when establishing comment periods. 

Additionally, some comments 

touched on issues that are also relevant 

to other EPA policies and programs. For 

example, some commenters asserted 

that the EPA should base air pollutant 

transport policy more on monitored data 

rather than modeling data to promptly 

address air pollution in areas where 

current monitoring data indicates an 

exceedance of the NAAQS. Other 

commenters recommended that the EPA 

consider strengthening cost thresholds 

for Reasonably Available Control 

Technology (RACT), a program that is 

applicable to certain existing sources in 

non-attainment areas. 

In addition to the engagement 

conducted prior to this proposed rule, 

EPA is providing the public, including 

those communities disproportionately 

impacted by the burdens of pollution, 

opportunities to engage in the EPA’s 

public comment period for this 

proposed rule, including by hosting a 

public hearing. This public hearing will 

occur according to the schedule 

identified in the Public Participation 

section of this proposed rule. 

IX. Costs, Benefits, and Other Impacts 

of the Proposed Rule 

In the Regulatory Impact Analysis for 

the proposed Federal Implementation 

Plan Addressing Regional Ozone 

Transport for the 2015 Ozone National 

Ambient Air Quality Standards (RIA), 

EPA estimated the benefits, compliance 

costs, and emissions changes that may 

result from the proposed rule for the 

analysis period 2023 to 2042. The 

estimated benefits and compliance costs 

are presented in detail in the RIA 

accompanying this proposed rule. EPA 

notes that for EGUs the estimated 

benefits and compliance costs are 

directly associated with generation 

shifting to minimize costs; fully 

operating existing SCRs during ozone 

season; fully operating existing SNCRs 

during ozone season; installing state-ofthe-art combustion controls; imposing 

backstop emission rate limits on certain 

units that lack SCR controls; and unitlevel decisions to retrofit or retire. EPA 

also notes that for non-EGUs the 

estimated benefits and compliance costs 

are directly associated with installing 

controls to meet the NOX emissions 

limits presented in Section I.B above. 

For EGUs, EPA analyzed this 

proposed rule’s emission budgets using 

uniform control stringency represented 

by $1,800 per ton of NOX (2016$) in 

2023 and $11,000 per ton of NOX

(2016$) in 2026. EPA also analyzed a 

more and a less stringent alternative. 

The more and less stringent alternatives 

differ from the proposed rule in that 

they set different NOX ozone season 

emission budgets for the affected EGUs 

and different dates for compliance with 

backstop emission rate limits. 

For non-EGUs, EPA analyzed this 

proposed rule using a marginal cost 

threshold of up to $7,500 per ton 

(2016$) for 2026 for the following 

emissions units and industries: 

Reciprocating internal combustion 

engines in Pipeline Transportation of 

Natural Gas; kilns in Cement and 

Cement Product Manufacturing; boilers 

and furnaces in Iron and Steel Mills and 

Ferroalloy Manufacturing; furnaces in 

Glass and Glass Product Manufacturing; 

and high-emitting boilers in Basic 

Chemical Manufacturing, Petroleum and 

Coal Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. The less 

stringent alternative assumes there are 

emissions limits for all emission units 

from the proposal except for highemitting boilers in Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. The more 

stringent alternative assumes emissions 

limits for all emission units from the 

proposed rule and all boilers, not just 

high-emitting boilers, in Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. 

Table IX–1 provides the projected 

2023 through 2027, 2030, 2035, and 

2042 EGU emission reductions for the 

evaluated regulatory control 

alternatives. For additional information 

on emissions changes, see Table 4.6 and 

Table 4–7 in Chapter 4 of the RIA. 

TABLE IX–1—EGU OZONE SEASON NOX EMISSIONS CHANGES AND ANNUAL EMISSIONS REDUCTIONS (TONS) FOR NOX, 

SO2, PM2.5, AND CO2 FOR THE REGULATORY CONTROL ALTERNATIVES FROM 2023–2042 

Proposed rule Less stringent 

alternative 

More stringent 

alternative 

2023: 

NOX (ozone season) ...................................................................................................... 6,000 6,000 7,000 

NOX (annual) .................................................................................................................. 10,000 10,000 10,000 

SO2 (annual) * ................................................................................................................. .......................... 1,000 2,000 

CO2 (annual, thousand metric) ...................................................................................... .......................... .......................... ..........................

PM2.5 (annual) ................................................................................................................ .......................... .......................... ..........................

2024: 

NOX (ozone season) ...................................................................................................... 26,000 14,000 29,000 

NOX (annual) .................................................................................................................. 42,000 22,000 45,000 

SO2 (annual) ................................................................................................................... 42,000 20,000 43,000 

CO2 (annual, thousand metric) ...................................................................................... 18,000 10,000 19,000 

PM2.5 (annual) ................................................................................................................ 4,000 1,000 4,000 

2025: 


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TABLE IX–1—EGU OZONE SEASON NOX EMISSIONS CHANGES AND ANNUAL EMISSIONS REDUCTIONS (TONS) FOR NOX, 

SO2, PM2.5, AND CO2 FOR THE REGULATORY CONTROL ALTERNATIVES FROM 2023–2042—Continued 

Proposed rule Less stringent 

alternative 

More stringent 

alternative 

NOX (ozone season) ...................................................................................................... 46,000 22,000 51,000 

NOX (annual) .................................................................................................................. 73,000 33,000 80,000 

SO2 (annual) ................................................................................................................... 83,000 39,000 84,000 

CO2 (annual, thousand metric) ...................................................................................... 37,000 19,000 38,000 

PM2.5 (annual) ................................................................................................................ 9,000 2,000 9,000 

2026: 

NOX (ozone season) ...................................................................................................... 47,000 32,000 53,000 

NOX (annual) .................................................................................................................. 81,000 55,000 87,000 

SO2 (annual) ................................................................................................................... 106,000 76,000 108,000 

CO2 (annual, thousand metric) ...................................................................................... 40,000 26,000 42,000 

PM2.5 (annual) ................................................................................................................ 9,000 5,000 9,000 

2027: 

NOX (ozone season) ...................................................................................................... 49,000 42,000 54,000 

NOX (annual) .................................................................................................................. 88,000 76,000 95,000 

SO2 (annual) ................................................................................................................... 129,000 113,000 131,000 

CO2 (annual, thousand metric) ...................................................................................... 43,000 34,000 46,000 

PM2.5 (annual) ................................................................................................................ 10,000 7,000 10,000 

2030: 

NOX (ozone season) ...................................................................................................... 52,000 52,000 57,000 

NOX (annual) .................................................................................................................. 96,000 98,000 100,000 

SO2 (annual) ................................................................................................................... 104,000 100,000 103,000 

CO2 (annual, thousand metric) ...................................................................................... 50,000 45,000 50,000 

PM2.5 (annual) ................................................................................................................ 9,000 9,000 9,000 

2035: 

NOX (ozone season) ...................................................................................................... 49,000 50,000 52,000 

NOX (annual) .................................................................................................................. 90,000 93,000 93,000 

SO2 (annual) ................................................................................................................... 96,000 93,000 98,000 

CO2 (annual, thousand metric) ...................................................................................... 38,000 36,000 38,000 

PM2.5 (annual) ................................................................................................................ 11,000 12,000 10,000 

2042: 

NOX (ozone season) ...................................................................................................... 47,000 47,000 48,000 

NOX (annual) .................................................................................................................. 70,000 75,000 71,000 

SO2 (annual) ................................................................................................................... 54,000 50,000 54,000 

CO2 (annual, thousand metric) ...................................................................................... 25,000 23,000 24,000 

PM2.5 (annual) ................................................................................................................ 8,000 9,000 8,000 

*SO2 emissions reductions under the proposed rule are 350 tons and rounded to zero. SO2 emissions reductions under the less stringent alternative are 507 tons and rounded to 1,000 tons. SO2 emissions reductions are 1,699 tons under the more stringent alternative and rounded to 

2,000 tons. Given the rounding, the difference between the reductions under the proposed rule and the less stringent alternative is approximately 

160 tons. 

Table IX–2 below provides a summary 

of the ozone season emissions for nonEGUs for the 23 states subject to the 

proposed non-EGU emissions limits 

starting in 2026, along with the 

estimated ozone season reductions for 

2026 for the proposed rule and the less 

and more stringent alternatives. The 

analysis in the RIA assumes that the 

estimated reductions in 2026 will be the 

same in later years. 

TABLE IX–2—OZONE SEASON (OS) NOX EMISSIONS AND EMISSIONS REDUCTIONS (TONS) FOR NON-EGUS FOR THE

PROPOSED RULE AND THE LESS AND MORE STRINGENT ALTERNATIVES * 

State 2019 OS NOX

emissions a

Proposed rule— 

OS NOX

reductions 

Less stringent 

alternative—OS 

NOX reductions 

More stringent 

alternative—OS 

NOX reductions 

AR .................................................................................................... 8,265 1,654 922 1,654 

CA .................................................................................................... 14,579 1,666 1,598 1,777 

IL ...................................................................................................... 16,870 2,452 2,452 2,553 

IN ..................................................................................................... 19,604 3,175 2,787 3,175

KY .................................................................................................... 11,934 2,291 2,291 2,291 

LA ..................................................................................................... 35,831 6,769 4,121 6,955

MD ................................................................................................... 2,365 45 45 45 

MI ..................................................................................................... 18,996 2,731 2,731 3,093

MN ................................................................................................... 17,591 673 673 789 

MO ................................................................................................... 9,109 3,103 3,103 3,103 

MS .................................................................................................... 12,284 1,761 1,577 1,761 

NJ ..................................................................................................... 2,025 0 0 29 

NV .................................................................................................... 2,418 0 0 0 

NY .................................................................................................... 6,003 500 389 613 

OH .................................................................................................... 19,729 2,790 2,611 2,814 

OK .................................................................................................... 22,146 3,575 3,575 3,871 


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TABLE IX–2—OZONE SEASON (OS) NOX EMISSIONS AND EMISSIONS REDUCTIONS (TONS) FOR NON-EGUS FOR THE

PROPOSED RULE AND THE LESS AND MORE STRINGENT ALTERNATIVES *—Continued 

State 2019 OS NOX

emissions a

Proposed rule— 

OS NOX

reductions 

Less stringent 

alternative—OS 

NOX reductions 

More stringent 

alternative—OS 

NOX reductions 

PA .................................................................................................... 15,861 3,284 3,132 3,340 

TX .................................................................................................... 47,135 4,440 4,440 6,596 

UT .................................................................................................... 6,276 757 757 757 

VA .................................................................................................... 7,041 1,563 1,465 1,660 

WI ..................................................................................................... 6,571 2,150 677 2,234 

WV ................................................................................................... 9,825 982 982 982 

WY ................................................................................................... 10,335 826 826 826 

Totals ........................................................................................ 322,793 47,186 41,153 50,918 

* In the non-EGU screening assessment for 2026, EPA estimated emissions reduction potential from the non-EGU industries and emissions 

units. In the screening assessment, EPA used CoST to identify emissions units, emissions reductions, and associated compliance costs to evaluate the effects of potential non-EGU emissions control measures and technologies. CoST is designed to be used for illustrative control strategy 

analyses (e.g., NAAQS regulatory impact analyses) and not for unit-specific, detailed engineering analyses. The estimates from CoST identify 

proxies for (1) non-EGU emissions units that have emissions reduction potential, (2) potential controls for and emissions reductions from these 

emissions units, and (3) control costs from the potential controls on these emissions units. The control cost estimates do not include monitoring, 

recordkeeping, reporting, or testing costs. This screening assessment is not intended to be, nor take the place of, a unit-specific detailed engineering analysis that fully evaluates the feasibility of retrofits for the emissions units, potential controls, and related costs. aEPA determined that the 2019 inventory was appropriate because it provided a more accurate prediction of potential near-term emissions reductions. The analysis in the RIA assumes that the 2019 ozone season emissions will be the same in 2026 and later years. 

For EGUs, the EPA analyzed ozone 

season NOX emission reductions and 

the associated costs to the power sector 

using the Integrated Planning Model 

(IPM) and its underlying data and 

inputs. For non-EGUs, the EPA analyzed 

ozone season NOX emission reductions 

and the associated costs for 2026 in the 

Non-EGU Screening Assessment 

memorandum. Table IX–3 reflects the 

estimates of the changes in the cost of 

supplying electricity for the regulatory 

control alternatives for EGUs and 

estimates of complying with the 

emissions limits for non-EGUs. For 

EGUs, compliance costs are negative in 

2023. While seemingly counterintuitive, 

estimating negative compliance costs in 

a single year is possible given IPM’s 

objective function is to minimize the 

discounted net present value (NPV) of a 

stream of annual total cost of generation 

over a multi-decadal time period. As 

such the model may undertake a 

compliance pathway that pushes higher 

costs later into the forecast period, since 

future costs are discounted more heavily 

than near term costs. This can result in 

a policy scenario showing single year 

costs that are lower than the Baseline, 

but over the entire forecast horizon, the 

policy scenario shows higher costs. For 

a detailed description of these cost 

trends, please see Chapter 4, Section 

4.5.2 of the RIA. For a detailed 

description of the methods and results 

from Non-EGU Screening Assessment 

memorandum, see Chapter 4, Sections 

4.4 and 4.5.2 of the RIA. 

TABLE IX–3—TOTAL ESTIMATED COMPLIANCE COSTS (MILLION 2016$), 2023–2042 

Proposed rule Less-stringent 

alternative 

More-stringent 

alternative 

2023: 

EGUs .......................................................................................................................... ¥209 ¥173 ¥178 

Non-EGUs .................................................................................................................. .......................... ............................ ............................

Total ............................................................................................................................ ¥209 ¥173 ¥178 

2026: 

EGUs .......................................................................................................................... 707 ¥406 1,180 

Non-EGUs .................................................................................................................. 411 357 445 

Total ............................................................................................................................ 1,117 ¥49 1,625 

2027: 

EGUs .......................................................................................................................... 1,544 1,540 1,983 

Non-EGUs .................................................................................................................. 411 357 445 

Total ............................................................................................................................ 1,955 1,896 2,428 

2030: 

EGUs .......................................................................................................................... 1,235 1,200 1,740 

Non-EGUs .................................................................................................................. 411 357 445 

Total ............................................................................................................................ 1,646 1,557 2,185 

2035: 

EGUs .......................................................................................................................... 1,729 1,596 2,335 

Non-EGUs .................................................................................................................. 411 357 445 

Total ............................................................................................................................ 2,139 1,953 2,780 

2042: 

EGUs .......................................................................................................................... 910 1,757 1,001 

Non-EGUs .................................................................................................................. 411 357 445 

Total ............................................................................................................................ 1,321 2,114 1,446 


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Tables IX–4 and IX–5 report the 

estimated economic value of avoided 

premature deaths and illness in each 

year relative to the baseline along with 

the 95% confidence interval. In each of 

these tables, for each discount rate and 

regulatory control alternative, multiple 

benefits estimates are presented 

reflecting alternative ozone and PM2.5

mortality risk estimates. For additional 

information on these benefits, see 

Chapter 5 of the RIA. 

TABLE IX–4—ESTIMATED DISCOUNTED ECONOMIC VALUE OF AVOIDED OZONE AND PM2.5-ATTRIBUTABLE PREMATURE

MORTALITY AND ILLNESS FOR THE PROPOSED POLICY SCENARIOS IN 2023 

[95% Confidence interval; millions of 2016$] a b

Disc. rate Pollutant Proposal More stringent alternative Less stringent alternative 

3% .......................... Ozone Benefits ..... $57 ($15 to $120) c and $460 ($51 to 

$1,200) d.

$65 ($17 to $140) c and $530 ($59 to 

$1,400) d.

$57 ($15 to $120) c and $460 ($51 to 

$1,200).d

PM Benefit Per 

Ton (BPT)s.

$44 and $45 ......................................... $190 and $190 ..................................... $59 and $60. 

Ozone Benefits 

plus PM BPTs.

$100 ($59 to $160) c and $500 ($96 to 

$1,200) d.

$250 ($200 to $330) c and $720 ($250 

to $1,600) d.

$120 ($74 to $180) c and $520 ($110 

to $1,300).d

7% .......................... Ozone Benefits ..... $51 ($9.6 to 110) c and $410 ($42 to 

$1,100) d.

$58 ($11 to $130) c and $480 ($49 to 

$1,300) d.

$51 ($9.6 to $110) c and $410 ($42 to 

$1,100).d

PM BPTs ............... $40 and $41 ......................................... $170 and $170 ..................................... $53 and $54. 

Ozone Benefits 

plus PM BPTs.

$90 ($49 to $150) c and $450 ($83 to 

$1,100) d.

$230 ($180 to $300) c and $650 ($220 

to $1,400) d.

$100 ($63 to $170) c and $470 ($97 to 

$1,100).d

aValues 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. bWe estimated ozone benefits for changes in NOX for the ozone season and changes in PM2.5 and PM2.5 precursors for EGUs in 2023. This table does not include 

benefits from reductions for non-EGUs because reductions from these sources are not expected prior to 2026 when the proposed standards would become effective. c Using the pooled short-term ozone exposure mortality risk estimate. 

d Using the long-term ozone exposure mortality risk estimate. 

TABLE IX–5—ESTIMATED DISCOUNTED ECONOMIC VALUE OF AVOIDED OZONE AND PM2.5-ATTRIBUTABLE PREMATURE

MORTALITY AND ILLNESS FOR THE PROPOSED POLICY SCENARIO IN 2026 

[95% Confidence interval; millions of 2016$] a b

Disc. rate Pollutant Proposal More stringent alternative Less stringent alternative 

3% .......................... Ozone Benefits ..... $1,200 ($310 to $2,600) c and $10,000 

($1,100 to $26,000) d.

$1,300 (340 to $2,900) c and $11,000 

($1,200 to $29,000) d.

$830 ($210 to $1,800) c and $6,900 

($760 to $18,000).d

PM BPTs ............... $8,100 and $8,300 ............................... $7,800 and $7,900 ............................... $3,400 and $3,500. 

Ozone Benefits 

plus PM BPTs.

$9,300 ($8,400 to $11,000) c and 

$18,000 ($9,400 to $35,000) d.

$9,100 ($8,100 to $11,000) c and 

$19,000 ($9,200 to $37,000) d.

$4,300 ($3,700 to $5,200) c and 

$10,000 ($4,300 to $22,000).d

7% .......................... Ozone Benefits ..... $1,100 ($200 to $2,400) c and $9,000 

($920 to $24,000) d.

$1,200 ($220 to $2,700) c and $10,000 

($1,000 to $26,000) d.

$740 ($140 to $1,700) c and $6,200 

($630 to $16,000).d

PM BPTs ............... $7,300 and $7,400 ............................... $7,000 and $7,100 ............................... $3,100 and $3,200. 

Ozone Benefits 

plus PM BPTs.

$8,400 ($7,500 to $9,700) c and 

$16,000 ($8,300 to $31,000) d.

$8,200 ($7,200 to $9,700) c and 

$17,000 ($8,200 to $34,000) d.

$3,800 ($3,200 to $4,800) c and 

$9,300 ($3,800 to $19,000).d

aValues 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. bWe estimated changes in NOX for the ozone season and changes in PM2.5 and PM2.5 precursors in 2026. This table represents changes in EGU and non-EGU 

ozone season and annual controls. cSum 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. dSum of the Turner et al. (2016) long-term ozone exposure risk estimate and the Di et al. (2017) long-term PM2.5 exposure mortality risk estimate. 

In Tables IX–6, IX–7, and IX–8, EPA 

presents a summary of the monetized 

benefits, costs, and net benefits of the 

proposal and the more and less stringent 

alternatives for 2023, 2026, and 2030, 

respectively. The monetized benefits 

estimates do not include important 

climate benefits that were not 

monetized in the RIA. In addition, there 

are important water quality benefits and 

health benefits associated with 

reductions in concentrations of air 

pollutants other than PM2.5 and ozone 

that are not quantified. We request 

comment on how to address the climate 

benefits and other categories of nonmonetized benefits of the proposed rule. 

Discussion of the non-monetized health, 

climate, welfare, and water quality 

benefits is found in Chapter 5 of the 

RIA. 

TABLE IX–6—MONETIZED BENEFITS, COSTS, AND NET BENEFITS OF THE PROPOSED AND LESS AND MORE STRINGENT

ALTERNATIVES FOR 2023 FOR THE U.S. 

[Millions of 2016$] a b

Proposed rule Less stringent alternative More stringent alternative 

Benefits c (3%) ............................... $100 and $500 ............................. $120 and $520 ............................. $250 and $720. 

Costs d ............................................ ¥$210 .......................................... ¥$170 .......................................... ¥$180. 

Net Benefits ................................... $310 and $710 ............................. $290 and $690 ............................. $430 and $900. 

Benefits c (7%) ............................... $90 and $450 ............................... $100 and $470 ............................. $230 and $650. 

Costs d ............................................ ¥$210 .......................................... ¥$170 .......................................... ¥$180 

Net Benefits ................................... $300 and $660 ............................. $280 and $640 ............................. $400 and $820. 

aWe 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. 


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c Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits 

are associated with several point estimates and are presented at a real discount rate of 3 percent. Several categories of benefits remain 

unmonetized and are thus not reflected in the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. 

The U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization of the benefits of greenhouse 

gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No. 21–cv–01074–JDC–KK (W.D. La. Feb. 11, 2022). Therefore, 

such values are not presented in the benefit-cost analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 

of the RIA for more discussion. In addition, there are important unquantified water quality benefits and benefits associated with reductions in 

other air pollutants. dThe costs presented in this table are 2023 annual estimates for each alternative analyzed. An NPV of costs was calculated using a 3.76% 

real discount rate consistent with the rate used in IPM’s objective function for cost-minimization. 

TABLE IX–7—MONETIZED BENEFITS, COSTS, AND NET BENEFITS OF THE PROPOSED AND LESS AND MORE STRINGENT

ALTERNATIVES FOR 2026 FOR THE U.S. 

[Millions of 2016$] a b

Proposed rule Less stringent alternative More stringent alternative 

Benefits c (3%) ............................... $9,300 and $18,000 ..................... $4,300 and $10,000 ..................... $9,100 and $19,000. 

Costs d ............................................ $1,100 ........................................... ¥$49 ............................................ $1,600. 

Net Benefits ................................... $8,200 and $17,000 ..................... $4,300 and $10,000 ..................... $7,500 and $17,000. 

Benefits c (7%) ............................... $8,400 and $16,000 ..................... $3,800 and $9,300 ....................... $8,200 and $17,000. 

Costs d ............................................ $1,100 ........................................... ¥$49 ............................................ $1,600 

Net Benefits ................................... $7,300 and $15,000 ..................... $9,300 and $3,900 ....................... $6,600 and $15,000. 

aWe focus results to provide a snapshot of costs and benefits in 2026, using the best available information to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates. b Rows may not appear to add correctly due to rounding. 

c Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits 

are associated with several point estimates and are presented at a real discount rate of 3 percent. Several categories of benefits remain 

unmonetized and are thus not reflected in the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. 

The U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization of the benefits of greenhouse 

gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No. 21–cv–01074–JDC–KK (W.D. La. Feb. 11, 2022). Therefore, 

such values are not presented in the benefit-cost analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 

of the RIA for more discussion. In addition, there are important unquantified water quality benefits and benefits associated with reductions in 

other air pollutants. dThe costs presented in this table are 2026 annual estimates for each alternative analyzed. An NPV of costs was calculated using a 3.76% 

real discount rate consistent with the rate used in IPM’s objective function for cost-minimization. 

TABLE IX–8—MONETIZED BENEFITS, COSTS, AND NET BENEFITS OF THE PROPOSED AND LESS AND MORE STRINGENT

ALTERNATIVES FOR 2030 FOR THE U.S. 

(Millions of 2016$) a b

Proposed rule Less stringent alternative More stringent alternative 

Benefits c (3%) ............................... $9,400 and $20,000 ..................... $4,300 and $11,000 ..................... $9,200 and $21,000. 

Costs d ............................................ $1,600 ........................................... $1,600 ........................................... $2,200. 

Net Benefits ................................... $7,700 and $18,000 ..................... $2,800 and $9,700 ....................... $7,000 and $19,000. 

Benefits c (7%) ............................... $8,400 and $18,000 ..................... $3,900 and $10,000 ..................... $8,300 and $19,000. 

Costs d ............................................ $1,600 ........................................... $1,600 ........................................... $2,200. 

Net Benefits ................................... $6,800 and $16,000 ..................... $2,300 and $8,400 ....................... $6,100 and $16,000. 

aWe focus results to provide a snapshot of costs and benefits in 2030, using the best available information to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates. b Rows may not appear to add correctly due to rounding. 

c Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The health benefits 

are associated with several point estimates and are presented at a real discount rate of 3 percent. Several categories of benefits remain 

unmonetized and are thus not reflected in the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. 

The U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization of the benefits of greenhouse 

gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No. 21–cv–01074–JDC–KK (W.D. La. Feb. 11, 2022). Therefore, 

such values are not presented in the benefit-cost analysis of this proposed rule conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for more discussion. In addition, there are important unquantified water quality benefits and benefits associated with reductions in other air pollutants. dThe costs presented in this table are 2030 annual estimates for each alternative analyzed. An NPV of costs was calculated using a 3.76% 

real discount rate consistent with the rate used in IPM’s objective function for cost-minimization. 

In addition, Table IX–9 presents 

estimates of the present value (PV) of 

the monetized benefits and costs and 

the equivalent annualized value (EAV), 

an estimate of the annualized value of 

the net benefits consistent with the 

present value, over the twenty-year 

period of 2023 to 2042. The estimates of 

the PV and EAV are calculated using 

discount rates of 3 and 7 percent as 

directed by OMB’s Circular A–4 and are 

presented in 2016 dollars discounted to 

2022. 


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TABLE IX–9—MONETIZED ESTIMATED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS OF THE PROPOSED RULE AND

LESS AND MORE STRINGENT ALTERNATIVES, 2023 THROUGH 2042 

(Millions 2016$, discounted to 2022) a

3 Percent discount rate 7 Percent discount rate 

PV EAV PV EAV 

Benefits 

Proposed Rule ................................................................................................. $250,000 $17,000 $150,000 $14,000 

Less Stringent Alternative ................................................................................ 150,000 9,500 88,000 7,800 

More Stringent Alternative ............................................................................... 270,000 17,000 160,000 14,000 

Compliance Costs 

Proposed Rule ................................................................................................. 22,000 1,500 14,000 1,300 

Less Stringent Alternative ................................................................................ 20,000 1,300 12,000 1,100 

More Stringent Alternative ............................................................................... 28,000 1,900 18,000 1,700 

Net Benefits 

Proposed Rule ................................................................................................. 220,000 15,000 130,000 12,000 

Less Stringent Alternative ................................................................................ 120,000 8,100 70,000 6,600 

More Stringent Alternative ............................................................................... 230,000 15,000 130,000 12,000 

aThe U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No. 21–cv–01074–JDC–KK (W.D. La. Feb. 11, 2022). 

Therefore, such values are not presented in the benefit-cost analysis of this proposed rule conducted pursuant to E.O. 12866. 

As shown in Table IX–9, the PV of the 

benefits of this proposed rule, 

discounted at a 3-percent discount rate, 

is estimated to be about $250,000 

million, with an EAV of about $17,000 

million. At a 7-percent discount rate, 

the PV of the benefits is estimated to be 

$150,000 million, with an EAV of about 

$14,000 million. The PV of the 

compliance costs, discounted at a 3- 

percent rate, is estimated to be about 

$22,000 million, with an EAV of about 

$1,500 million. At a 7-percent discount 

rate, the PV of the compliance costs is 

estimated to be about $14,000 million, 

with an EAV of about $1,300 million. 

In addition to the analysis of costs 

and benefits, EPA also estimated the 

impacts on projected 2023 and 2026 

ozone design values that are expected 

from the EGU and non-EGU control 

alternatives in this proposed rule. As 

described above, the alternative 

scenarios include the proposed rule 

along with scenarios that reflect less 

stringent and more stringent alternatives 

for EGUs and non-EGUs. The projected 

ozone design values and ozone impacts 

estimated in 2023 and 2026 for the 

proposed, less stringent, and more 

stringent alternatives are provided in 

Appendix 3B of the RIA. In summary, 

the differences in the amount of ozone 

reduction across the three alternatives at 

individual receptors in 2023 are 

consistent with the relative changes in 

NOX emissions in this year under the 

different scenarios. Overall, in 2023 the 

estimated ozone reductions from all 

three of the alternatives are projected to 

be less than 0.1 ppb at most receptors. 

The exceptions are at certain receptors 

in Connecticut, Illinois, Texas, and Utah 

where impacts are between 0.1 and 0.2 

ppb. In 2026, the largest impacts in the 

proposed rule are estimated at the two 

receptors in Texas (i.e., Brazoria County 

and Harris County), where the average 

reduction is 1.3 ppb. Elsewhere in 2026, 

the average reductions for the proposed 

rule are on the order of 0.5 ppb at 

receptors in Connecticut, Illinois, and 

Wisconsin. The average reduction for 

the four receptors in Utah is 

approximately 0.3 ppb, while the 

average reduction at receptors in 

Colorado and California are 

approximately 0.2 ppb. Overall, the less 

stringent alternative provides 

approximately 0.1 to 0.3 ppb less ppb 

reduction (i.e., 30 to 40 percent less 

reduction), on average, compared to the 

proposed rule at receptors in the East 

and in Colorado and Utah. The more 

stringent alternative does not appear to 

provide any notable additional ozone 

reductions compared to the proposed 

rule in all receptor areas, except at 

receptors in Connecticut and Texas 

where the average reduction increases 

by 0.1 ppb and 0.2 ppb with the more 

stringent alternative, respectively. 

Examining the projected average and 

maximum design values in 2023 at 

individual receptors for the proposed, 

less stringent, and more stringent 

alternatives indicates that three of the 

receptors included in this impact 

analysis are projected to change 

attainment status in 2023 as a result of 

this proposed rule. Specifically, 

receptors in Clark County, Nevada, 

Butte County, California, and Riverside 

County Californian (Monitor ID: 

060650008) are projected to switch from 

maintenance-only in the 2023 baseline 

to attainment and the receptor in Harris 

County, Texas is projected to switch 

from nonattainment to maintenanceonly under any of the alternatives in 

2023. In 2026, six of the receptors in 

this analysis are projected to change 

attainment status as a result of the 

emissions reductions in this proposed 

rule. Specifically, Calaveras County, 

California, Brazoria County, Texas, and 

in Kenosha County, Wisconsin (Monitor 

ID: 550590025) are projected to switch 

from maintenance-only to attainment in 

2026 and a receptor in Riverside 

County, California (Monitor ID: 

060650016) is projected to switch from 

nonattainment to maintenance under 

any of the alternatives. The receptor in 

Douglas County, Colorado and one of 

the receptors in Cook County, Illinois 

(Monitor ID: 170310076) are projected to 

switch from maintenance-only to 

attainment under the proposed and 

more stringent alternatives, but these 

receptors are projected to remain as 

maintenance-only in the less stringent 

alternative. The projected design values 

and additional information on the ozone 

impact analysis can be found in 

Appendix 3B of the proposed rule RIA. 

X. Summary of Proposed Changes to the 

Regulatory Text for the Federal 

Implementation Plans and Trading 

Programs for EGUs 

This section describes the proposed 

amendments to the regulatory text that 


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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20161 

339Both the current text of § 52.38(b)(2) and the 

proposed amended text expressly encompass 

sources in Indian country within the respective 

states’ borders. 

340No state currently in the Group 3 trading 

program has submitted a SIP revision to make use 

of these options in control periods before the 

control periods in which the options could be used 

under the proposed amendments. 

would implement the proposed findings 

and remedy discussed elsewhere in this 

proposed rule with respect to EGUs. The 

primary CFR amendments would be 

revisions to the FIP provisions 

addressing states’ good neighbor 

obligations related to ozone in 40 CFR 

part 52 as well as the revisions to the 

regulations for the CSAPR NOX Ozone 

Season Group 3 Trading Program in 40 

CFR part 97, subpart GGGGG. In 

conjunction with the amendments to the 

Group 3 trading program, the 

monitoring, recordkeeping, and 

reporting regulations in 40 CFR part 75 

would be amended to reflect the 

addition of certain new reporting 

requirements associated with the 

amended trading program and the 

administrative appeal provisions in 40 

CFR part 78 would be amended to 

identify certain additional types of 

appealable decisions of the EPA 

Administrator under the amended 

trading program. The proposed 

provisions to address the transition of 

the EGUs in certain states from the 

Group 2 trading program to the Group 

3 trading program would be 

implemented in part through revisions 

to regulations noted above and in part 

through revisions to the regulations for 

the Group 2 trading program in 40 CFR 

part 97, subpart EEEEE. 

In addition to these primary 

amendments, certain revisions are 

proposed to the regulations for the other 

CSAPR trading programs in 40 CFR part 

97, subparts AAAAA through EEEEE, 

and the Texas SO2 Trading Program in 

40 CFR part 97, subpart FFFFF, for 

conformity with the proposed amended 

provisions of the Group 3 trading 

program, as discussed in Section 

VII.B.12 of this proposed rule. 

Documents have been included in the 

docket for this proposed rule showing 

all of the proposed revisions in redlinestrikeout 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 § 52.38(b)(1) identifies 

the trading program regulations in 40 

CFR part 97, subparts BBBBB, EEEEE, 

and GGGGG as constituting the relevant 

FIP provisions relating to seasonal NOX

emissions and transported ozone 

pollution. Because the EPA is proposing 

in this rulemaking to establish new or 

amended FIP requirements not only for 

the types of EGUs covered by the 

trading programs but also for other types 

of sources, a proposed amendment to 

§ 52.38(b)(1) would clarify that the 

trading programs constitute the FIP 

provisions only for the sources meeting 

the applicability requirements of the 

trading programs. A parallel 

clarification would be added to 

§§ 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 § 52.38(b)(2). Proposed 

amendments to this paragraph would 

expand the applicability of the Group 3 

trading program to sources in the 

thirteen additional states that the EPA is 

proposing to add to the Group 3 trading 

program starting with the 2023 control 

period and would end the applicability 

of the Group 2 trading program (with 

the exception of certain provisions) for 

sources in eight of the thirteen states 

after the 2022 control period, as 

discussed in Section VII.B.2 of this 

proposed rule.339 The current 

subparagraphs within § 52.38(b)(2) 

would also be renumbered to clarify the 

organization of the provisions and to 

facilitate cross-references from other 

regulatory provisions. Regarding the two 

states currently participating in the 

Group 2 trading program through 

approved SIP revisions that replaced the 

previous FIPs issued under the CSAPR 

Update (Alabama and Missouri), a 

provision indicating that EPA would no 

longer administer the state trading 

programs adopted under those SIP 

revisions after the 2022 control period 

would be added at § 52.38(b)(16)(ii)(B). 

In the Revised CSAPR Update, the 

EPA established several options for 

states to revise their SIPs to modify or 

replace the FIPs applicable to their 

sources while continuing to use the 

Group 3 trading program as the 

mechanism for meeting the states’ good 

neighbor obligations. Existing 

§ 52.38(b)(10), (11), and (12) establish 

options to replace allowance allocations 

for the 2022 control period, to adopt an 

abbreviated SIP revision for control 

periods in 2023 or later years, and to 

adopt a full SIP revision for control 

periods in 2023 or later years, 

respectively. As discussed in Section 

VII.D of this proposed rule, the EPA is 

proposing to retain these SIP revision 

options and to make them available for 

all states that would be covered by the 

Group 3 trading program after the 

proposed geographic expansion. The 

option under § 52.38(b)(10) to replace 

allowance allocations for a single 

control period would be amended to be 

available for the 2024 control period, 

with attendant revisions to the years 

and dates shown in § 52.38(b)(10) 

(multiple paragraphs) and (b)(17)(i) as 

well as the Group 3 trading program 

regulations, as discussed in Section X.B 

of this proposed rule. The options under 

§ 52.38(b)(11) and (12) to adopt 

abbreviated or full SIP revisions would 

be amended to be available starting with 

the 2025 control period, with attendant 

revisions to § 52.38(b)(11)(iii), 

(b)(12)(iii), and (b)(17)(ii).340

The proposed changes with respect to 

set-asides, the treatment of units in 

Indian country, and recordation 

schedules discussed in Section VII.B.9 

of this proposed rule, although 

implemented largely through proposed 

amendments to the Group 3 trading 

program regulations, would also be 

implemented in part through proposed 

amendments to § 52.38(b)(11) and (12). 

First, the text in § 52.38(b)(11)(iii)(A) 

and (b)(12)(iii)(A) identifying the 

portion of each state trading budget for 

which a state could establish statedetermined allowance allocations 

would be revised to exclude any 

allowances in a new unit set-aside, 

Indian country new unit set-aside, or 

Indian country existing unit set-aside. 

Second, the text in § 52.38(b)(12)(vi) 

identifying provisions that states could 

not adopt into their SIPs (because the 

provisions concern regulation of sources 

in Indian country not subject to a state’s 

CAA implementation planning 

authority) would be revised to include 

the provisions of the amended Group 3 

trading program addressing allocation 

and recordation of allowances from all 

types of set-asides. Third, the text in 

§ 52.38(b)(12)(vii) authorizing the EPA 

to modify the previous approval of a SIP 

revision with regard to the assurance 

provisions ‘‘if and when a covered unit 

is located in Indian country’’ would be 

revised to account for the fact that at 

least one covered unit would already be 

located in Indian country not subject to 

a state’s jurisdiction if the geographic 

expansion proposed in this rulemaking 


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341See proposed §§ 52.54(b) (Alabama), 52.184(a) 

(Arkansas), 52.440(d) (Delaware), 52.1240(d) 

(Minnesota), 52.1824(a) (Mississippi), 52.1326(b) 

(Missouri), 52.1492 (Nevada), 52.1930(a) 

(Oklahoma), 52.2240(e) (Tennessee), 52.2283(d) 

(Texas), 52.2356 (Utah), 52.2587(e) (Wisconsin), 

and 52.2638(a) (Wyoming). 

342See proposed §§ 52.54(b) (Alabama), 52.184(a) 

(Arkansas), 52.1824(a) (Mississippi), 52.1326(b) 

(Missouri), 52.1930(a) (Oklahoma), 52.2240(e) 

(Tennessee), 52.2283(d) (Texas), and 52.2587(e) 

(Wisconsin). 

343See proposed §§ 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). 

is finalized. Finally, the text in 

§ 52.38(b)(11)(iii)(B) and (b)(12)(iii)(B) 

would be revised to amend the deadline 

for states to submit state-determined 

allowance allocations to the EPA from 

June 1 in the third year before the 

relevant control period to June 1 in the 

year before the relevant control period. 

The proposed transitional provisions 

discussed in Section VII.B.11 of this 

proposed rule to convert certain 2017– 

2022 Group 2 allowances to Group 3 

allowances and to recall certain 2023– 

2024 Group 2 allowances, although 

promulgated as amendments to the 

Group 2 trading program regulations, 

would necessarily be implemented after 

the end of the 2022 control period. 

Proposed amendments clarifying that 

these provisions continue to apply to 

the relevant sources and holders of 

allowances notwithstanding the 

transition of certain states out of the 

Group 2 trading program after the 2022 

control period would be added at 

§ 52.38(b)(14)(iii)(F) and (G). Crossreferences clarifying that EPA’s 

allocations of the converted Group 3 

allowances would not be subject to 

modification through SIP revisions 

would also be added to the existing 

provisions at § 52.38(b)(11)(iii)(D) and 

(b)(12)(iii)(D). 

The general FIP provisions applicable 

to all states covered by this proposed 

rule as set forth in § 52.38(b)(2) would 

be replicated in the state-specific 

subparts of 40 CFR part 52 for each of 

the thirteen states that the EPA is 

proposing to add to the Group 3 trading 

program.341 In each such state-specific 

CFR subpart, provisions would be 

added indicating that sources in the 

state are required to participate in the 

CSAPR NOX Ozone Season Group 3 

Trading Program with respect to 

emissions starting in 2023. Provisions 

would also be added repeating the 

substance of § 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 § 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 statedetermined allowance allocations. 

For each of the eight states that the 

EPA is proposing to remove from the 

Group 2 trading program, the current 

provisions of the state-specific CFR 

subparts indicating that sources in the 

state are required to participate in that 

trading program would be revised to 

end that requirement with respect to 

emissions after 2022, and a further 

provision would be added repeating the 

substance of § 52.38(b)(14)(iii), which 

identifies certain provisions that 

continue to apply to sources and 

allowances notwithstanding 

discontinuation of a trading program 

with respect to a particular state.342 In 

addition, for the six states that during 

their time in the Group 2 trading 

program have not exercised the option 

to adopt full SIP revisions to replace the 

FIPs issued under the CSAPR Update 

(all but Alabama and Missouri), obsolete 

provisions concerning the unexercised 

SIP revision option would be removed. 

No amendments with respect to FIP 

requirements for EGUs would be made 

to the state-specific CFR subparts for the 

twelve states whose sources currently 

participate in the Group 3 trading 

program 343 except as needed to update 

cross-references or to implement the 

proposed changes related to the 

treatment of Indian country, as 

discussed in Section X.D of this 

proposed rule. 

B. Amendments to Group 3 Trading 

Program and Related Regulations 

To implement the geographic 

expansion of the Group 3 trading 

program and the revised trading budgets 

that would be established under the 

new and amended FIPs proposed in this 

rulemaking, several sections of the 

Group 3 trading program regulations 

would be amended. Revisions 

identifying the applicable control 

periods, deadlines for certification of 

monitoring systems, and deadlines for 

commencement of quarterly reporting 

for sources not previously covered by 

the Group 3 trading program would be 

made at §§ 97.1006(c)(3)(i), 

97.1030(b)(1), and 97.1034(d)(2)(i), 

respectively. Revisions identifying the 

proposed new or revised budgets and 

new unit set-asides for the 2023 and 

2024 control periods for all covered 

states would be made at § 97.1010(a)(1) 

and (b)(1), respectively. 

Each of the proposed enhancements 

to the Group 3 trading program 

discussed in Section VII.B of this 

proposed rule would also be 

implemented primarily through 

revisions to the trading program 

regulations. The dynamic budget-setting 

process discussed in Section VII.B.4 of 

this proposed rule would be 

implemented at § 97.1010(a)(2) and (3), 

and the associated revised process for 

determining variability limits and 

assurance levels discussed in Section 

VII.B.5 of this proposed rule would be 

implemented at § 97.1010(e). The Group 

3 allowance bank recalibration process 

discussed in Section VII.B.6 of this 

proposed rule would be implemented at 

§ 97.1026(d). The backstop daily NOX

emissions rate component of the 

primary emissions limitation discussed 

in Section VII.B.7 would be 

implemented at §§ 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 § 97.1002. The secondary 

emissions limitation for sources found 

responsible for exceedances of the 

assurance levels discussed in Section 

VII.B.8 of this proposed rule would be 

implemented at §§ 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 § 97.1002. 

The proposed changes relating to setasides, the treatment of Indian country, 

unit-level allowance allocations, and 

recordation schedules discussed in 

Section VII.B.9 of this proposed rule 

would be implemented through 

revisions to multiple sections of 

§§ 97.1010, 97.1011, 97.1012, and 

97.1021, as well as limited revisions to 

97.1002 (definition of ‘‘allocate or 

allocation’’) and 97.1006(b)(2). In 

§ 97.1010, paragraphs (b), (c), and (d) 

would address the amounts for each 

control period of the new unit setasides, Indian country new unit setasides, and Indian country existing unit 

set-asides, respectively. Paragraphs (c) 

and (d) would reflect the 

discontinuation of Indian country new 

unit set-asides after the 2022 control 

period and the establishment of Indian 


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344The current § 97.1011(c), which addresses the 

relationships of set-asides and variability limits to 

state trading budgets, would be relocated to 

§ 97.1011(f). 

345An additional provision currently in 

§ 97.1011(a)(1), which clarifies that an allocation or 

lack of allocation to a unit in a NODA does not 

constitute a determination by the EPA that the unit 

is or is not a CSAPR NOX Ozone Season Group 3 

unit, would be relocated to § 97.1011(a)(3). The 

current § 97.1011(a)(2), which provides for certain 

existing units that cease operations to receive 

allocations for their first five control periods of nonoperation and provides for the allowances for 

subsequent control periods to be allocated to the 

relevant state’s new unit set-asides, is inconsistent 

with the proposed revisions to the set-asides and 

the default allowance allocation process, as 

discussed in Section VII.B.9 of this proposed rule, 

and would be removed as obsolete. 

346Revisions are also proposed to the text of 

§ 97.1012(a) and (b) for the control periods in 2021 

and 2022 consistent with the proposed revisions to 

the parallel provisions in the regulations for the 

other CSAPR trading programs, generally calling for 

allocations to units in areas of Indian country 

subject to a state’s CAA implementation planning 

authority to be made from the new unit set-asides 

instead of from the Indian country new unit setasides. 

country existing unit set-asides starting 

with the 2023 control period.344

The proposed revisions to § 97.1011 

would refocus the section exclusively 

on allocation to ‘‘existing’’ units from 

the portion of each state emissions 

budget not reserved in a new unit setaside or Indian country new unit setaside. In § 97.1011(a), the provision 

currently in § 97.1011(a)(1) requiring 

allocations to existing units to be made 

in the amounts provided in notices of 

data availability (NODAs) issued by the 

EPA would be split into two separate 

provisions, with paragraph (a)(1) 

applying to existing units in the state 

and areas of Indian country covered by 

the state’s CAA implementation 

planning authority and paragraph (a)(2) 

applying to existing units in areas of 

Indian country not covered by the 

state’s CAA implementation planning 

authority.345 This split would facilitate 

the submission and approval of SIP 

revisions by states interested in 

submitting state-determined allowance 

allocations for the units over which they 

exercise CAA implementation authority, 

while leaving allocations to any units 

outside their authority to be addressed 

either by the EPA or by the relevant 

tribe under an approved tribal 

implementation plan. The proposed 

dynamic process for determining default 

allocations to existing units of 

allowances from state trading budgets 

starting with the 2025 control period 

would be set forth in revised 

§ 97.1011(b), while the current 

provisions of § 97.1011(b), which 

concern timing and notice procedures 

for allocations to new units, would be 

relocated to § 97.1012. The provisions 

addressing incorrectly allocated 

allowances at § 97.1011(c) would be 

streamlined by relocating the portions 

applicable to new units to § 97.1012(c). 

In addition, as discussed in Section 

VII.B.9.d of this proposed rule, 

§ 97.1011(c)(5) would be revised to 

provide that, starting with the 2024 

control period, any incorrectly allocated 

allowances recovered after May 1 of the 

year following the control period would 

not be reallocated to other units in the 

state but instead would be transferred to 

a surrender account. 

The proposed revisions to § 97.1012 

would retain the section’s current focus 

on allocations to ‘‘new’’ units, generally 

combining the current provisions at 

§ 97.1012 with the current provisions at 

§ 97.1011(b) and (c) that address new 

units. The text of multiple paragraphs in 

both § 97.1012(a) and (b) would be 

revised as needed to reflect the change 

in treatment of Indian country discussed 

in Section VII.B.9.a of this proposed 

rule, under which the new unit setasides would be used to provide 

allowance allocations to new units both 

in non-Indian country and Indian 

country within the borders of the 

respective states for control periods 

starting in 2023.346 The timing and 

notice provisions in proposed 

§ 97.1012(a)(13) and (b)(13) are 

relocated from current § 97.1011(b)(1) 

and (2). The text of § 97.1012(c), 

addressing incorrect allocations to new 

units, is largely relocated from 

§ 97.1011(c) (which addresses incorrect 

allocations to existing units) and reflects 

a parallel proposed revision addressing 

the disposition of recovered allowances, 

as discussed in Section VII.B.9.d of this 

proposed rule. 

The proposed amendments to 

§ 97.1021 would implement three 

distinct sets of changes discussed in 

Sections VII.B.9 and VII.D.1 of this 

proposed rule. First, revisions to 

§ 97.1021(b) through (e) would replace 

the previous schedule for recording 

Group 3 allowances for the 2023 and 

2024 control periods established in the 

Revised CSAPR Update with an updated 

recordation schedule tailored to the 

expected timing for issuance of a final 

rule in this rulemaking. The updated 

schedule would also reflect elimination 

of the unused former option for states to 

provide state-determined allowance 

allocations for the 2022 control period 

and the proposed establishment of a 

substantively equivalent new option for 

states to provide state-determined 

allowance allocations for the 2024 

control period. Second, revisions to 

§ 97.1021(f) would change the schedule 

for recording allocations to existing 

units for future control periods from 

July 1 of the year three years before the 

control period to July 1 of the year 

before the control period. Finally, 

revisions to § 97.1021(g) through (j) 

would end recordation for Indian 

country new unit set-asides after 

allocations for the 2022 control period, 

begin recordation for Indian country 

existing unit set-asides starting with 

allocations for the 2023 control period, 

and modify the text to eliminate 

references to state-determined 

allocations of allowances from new unit 

set-asides. 

Implementation of the proposed 

revisions to the Group 3 trading 

program would also be accomplished in 

part through amendments to regulations 

in other CFR parts. In 40 CFR part 75, 

which contains detailed monitoring, 

recordkeeping, and reporting 

requirements applicable to sources 

covered by the Group 3 trading program, 

the additional recordkeeping and 

reporting requirements discussed in 

Section VII.B.10.b of this proposed rule 

would be implemented through the 

addition of §§ 75.72(f) and 75.73(f)(1)(ix) 

and (x) and revisions to § 75.75, and the 

procedures for calculating daily total 

heat input and daily total NOX

emissions and for apportioning NOX

mass emissions monitored at a common 

stack among the individual units using 

the common stack would be added at 

sections 5.3.3, 8.4(c), and 8.5.3 of 

appendix F to part 75. In 40 CFR part 

78, which contains the administrative 

appeal procedures applicable to 

decisions of the EPA Administrator 

under the Group 3 trading program, 

§ 78.1(b)(19) would be amended to list 

additional decisions made as part of the 

trading program enhancements that 

would be appealable under those 

procedures. 

C. Transitional Provisions 

As discussed in Section VII.D.11 of 

this proposed rule, the EPA is proposing 

several transitional provisions for 

sources entering the Group 3 trading 

program. The provisions discussed in 

Section VII.D.11.a of this proposed rule, 

concerning the prorating of state 

emissions budgets, assurance levels, and 

unit-level allocations for the 2023 

control period, would be implemented 

through the Group 3 trading program 

regulations. Specifically, the state 

emissions budgets for the 2023 control 

period would be prorated according to 

procedures set out at § 97.1010(a)(1)(ii). 

Variability limits for the 2023 control 

period, and the resulting assurance 

levels, would be computed under 

§ 97.1010(e) from the prorated state 

emissions budgets. Unit-level 


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347The current provisions at § 97.826(e) would be 

relocated to § 97.826(f)(1) and (3). 

allocations to existing units for the 2023 

control period would be computed from 

the prorated state emissions budgets 

according to procedures substantively 

the same as the procedures codified in 

§ 97.1011(b) for calculating default 

allocations to existing units for later 

control periods, as discussed in Section 

VII.B.9.b of this proposed rule, and 

would be announced in the notice of 

data availability issued under 

§ 97.1011(a)(1) and (2) for the 2023 and 

2024 control periods. 

The remaining transitional provisions 

would be implemented through the 

Group 2 trading program regulations. 

The creation of an additional Group 3 

allowance bank for the 2023 control 

period through the conversion of 

banked 2017–2022 Group 2 allowances 

as discussed in Section VII.B.11.b of this 

document would be implemented at 

§ 97.826(e).347 Related provisions 

addressing the use of Group 3 

allowances to satisfy after-arising 

compliance obligations under the Group 

2 trading program or the Group 1 

trading program would be implemented 

at §§ 97.826(f)(2) and 97.526(e)(3), 

respectively, and related provisions 

addressing recordation of late-arising 

allocations of Group 1 allowances 

would be implemented at 

§ 97.526(d)(2)(iii). The recall of Group 2 

allowances previously issued for the 

2023 and 2024 control periods as 

discussed in Section VII.B.11.c of this 

document would be implemented at 

§ 97.811(e). 

Decisions of the Administrator related 

to the allowance bank creation 

provisions and the allowance recall 

provisions would be identified as 

appealable decisions under 40 CFR part 

78 through revisions to 

§ 78.1(b)(17)(viii) and (ix). 

D. Clarifications and Conforming 

Revisions 

As discussed in Section VII.B.12 of 

this proposed rule, the EPA is proposing 

to make revisions to the provisions 

regarding allowance allocations for 

units in Indian country in all the CSAPR 

trading programs so that instead of 

distinguishing among units based on 

whether they are or are not located in 

Indian country, the revised provisions 

would distinguish among units based on 

whether they are or are not covered by 

a state’s CAA implementation planning 

authority. The proposed revisions 

would be implemented in multiple 

paragraphs of §§ 97.411(b), 97.412, 

97.511(b), 97.512, 97.611(b), 97.612, 

97.711(b), 97.712, 97.811(b), and 97.812. 

The associated revisions to states’ 

options regarding SIP revisions to 

establish state-determined allowance 

allocations for units covered by their 

CAA implementation planning 

authority would be implemented in 

multiple paragraphs of §§ 52.38(a) and 

(b) and 52.39 as well as the statespecific subparts of 40 CFR part 52. 

As also discussed in Section VII.B.12 

of this proposed rule, the EPA is 

proposing to revise the recordation 

schedule for allowance allocations to 

existing units under all the CSAPR 

trading programs, as well as the Texas 

SO2 Trading Program, so that starting 

with the 2025 control period the 

allocation deadline would generally be 

July 1 of the year before the control 

period instead of July 1 of the year 3 

years before the control period. The 

revisions would be implemented at 

§§ 97.421(f)(2), 97.521(f)(2), 97.621(f)(2), 

97.721(f)(2), 97.821(f), and 97.921(b)(2). 

Certain other revisions to the 

regulatory text in the FIP and trading 

program regulations are proposed as 

non-substantive clarifications. First, in 

the Group 2 trading program 

regulations, the paragraphs in § 97.810 

setting forth the amounts of state 

emissions budgets, new unit set-asides, 

Indian country new unit set-asides, and 

variability limits for states that the EPA 

is proposing to transition out of the 

Group 2 trading program would be 

modified to indicate that the amounts 

are applicable under that program only 

for control periods through 2022. 

Second, as noted in Section VII.F.1 of 

this proposed rule, the existing option 

for states subject to the NOX SIP Call to 

expand applicability of the Group 2 

trading program to include certain large 

non-EGU boilers and combustion 

turbines would become obsolete if this 

rule is finalized as proposed because no 

NOX SIP Call states would continue to 

be covered by the Group 2 trading 

program. The proposed elimination of 

the obsolete option would be 

implemented in part through revisions 

to § 52.38(b)(8) (multiple paragraphs), 

(b)(9) (multiple paragraphs), (b)(13)(ii), 

(b)(14)(i)(F), and (b)(16)(i)(B), and in 

part through revisions to the Group 2 

trading program regulations at 

§§ 97.806(c)(2) and (3), 97.825, and 

97.802 (removal of the definitions of 

‘‘base CSAPR NOX Ozone Season Group 

2 source’’ and ‘‘base CSAPR NOX Ozone 

Season Group 2 unit’’ and modification 

of the definitions of ‘‘assurance 

account’’, ‘‘common designated 

representative’’, common designated 

representative’s assurance level’’, and 

‘‘common designated representative’s 

share’’). 

Third, to clarify the regulatory text, 

the EPA is proposing to remove the 

language in the Group 3 trading program 

regulations finalized in the Revised 

CSAPR Update relating to the 

‘‘supplemental allowances’’ issued for 

the 2021 control period in current 

§§ 97.1002 (definition of ‘‘common 

designated representative’s assurance 

level’’), 97.1006(c)(2)(iii), 97.1010(d), 

and 97.1011(a)(1). In place of the 

removed language, the EPA proposes to 

restate the amounts of the state 

emissions budgets for the 2021 control 

period in § 97.1010(a)(1)(i) so as to 

include the amounts of the 

supplemental allowances in the restated 

budget amounts. The revised language 

would be substantively equivalent to 

and simpler than the current language. 

Fourth, in 40 CFR part 75, the EPA 

proposes to remove obsolete text in 

§ 75.73(c) and (f) to clarify the context 

for other text that would be added to the 

section, as discussed in Section X.B. 

Finally, the EPA proposes to update 

cross-references throughout 40 CFR 

parts 52 and 97 for consistency with the 

other amendments proposed in this 

rulemaking. 

XI. Statutory and Executive Orders 

Reviews 

Additional information about these 

statutes and Executive Orders (‘‘E.O.’’) 

can be found at http://www2.epa.gov/ 

laws-regulations/laws-and-executiveorders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This proposed rule is an economically 

significant regulatory action that was 

submitted to the Office of Management 

and Budget (OMB) for review. This 

proposed rule is in response to a courtordered legal mandate and proposes to 

implement EGU and novel non-EGU 

NOX ozone season emissions reductions 

as part of the overall strategy for 

addressing interstate transport of ozone 

pollution for the 2015 ozone NAAQS. 

Any changes made in response to OMB 

recommendations have been 

documented in the docket. The EPA 

prepared an analysis of the potential 

costs and benefits associated with this 

proposed rule. This analysis, which is 

contained in the ‘‘Regulatory Impact 

Analysis for the Proposed Federal 

Implementation Plan Addressing 

Regional Ozone Transport for the 2015 

Ozone National Ambient Air Quality 

Standard’’ [EPA–452/R–15–009], is 

available in the docket and is briefly 

summarized in Section IX of this 

proposed rule. 


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B. Paperwork Reduction Act (PRA) 

1. Information Collection Request for 

Electric Generating Units 

The information collection activities 

in this proposed rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the PRA. The Information Collection 

Request (ICR) document that the EPA 

prepared has been assigned EPA ICR 

number 2709.01. EPA has placed a copy 

of the ICR in the docket for this rule, 

and it is briefly summarized here. 

EPA is proposing an information 

collection request (ICR), related 

specifically to electric generating units 

(EGU), for the proposed Federal 

Implementation Plan Addressing 

Regional Ozone Transport for the 2015 

Primary Ozone National Ambient Air 

Quality Standard. The proposed rule 

would amend the Cross-State Air 

Pollution Rule (CSAPR) NOX Ozone 

Season Group 3 trading program 

addressing seasonal NOX emissions in 

various states. Under the proposed 

amendments, all EGU sources in the 

original twelve Group 3 states (Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Michigan, New Jersey, New 

York, Ohio, Pennsylvania, Virginia, and 

West Virginia) would remain. 

Additionally, EGU sources in eight 

states (Alabama, Arkansas, Mississippi, 

Missouri, Oklahoma, Tennessee, Texas, 

and Wisconsin) currently covered by the 

CSAPR NOX Ozone Season Group 2 

Trading Program would transition from 

the Group 2 program to the revised 

Group 3 trading program beginning with 

the 2023 ozone season. Further, sources 

in five states not currently covered by 

any CSAPR NOX ozone season trading 

program would join the revised Group 

3 trading program: Delaware, 

Minnesota, Nevada, Utah, and 

Wyoming. In total, EGU sources in 25 

states would now be covered by the 

Group 3 program. 

There is an existing ICR (OMB Control 

Number 2060–0667), that includes 

information collection requirements 

placed on EGU sources for the six CrossState Air Pollution Rule (CSAPR) 

trading programs addressing sulfur 

dioxide (SO2) emissions, annual 

nitrogen oxides (NOX) emissions, or 

seasonal NOX emissions in various sets 

of states, and the Texas SO2 trading 

program which is modeled after CSAPR. 

This ICR accounts for the additional 

respondent burden related to the 

amendments to the CSAPR NOX Ozone 

Group 3 trading program. 

The principal information collection 

requirements under the CSAPR and 

Texas trading programs relate to the 

monitoring and reporting of emissions 

and associated data in accordance with 

40 CFR part 75. Other information 

collection requirements under the 

programs concern the submittal of 

information necessary to allocate and 

transfer emission allowances and the 

submittal of certificates of 

representation and other typically onetime registration forms. 

Affected sources under the CSAPR 

and Texas trading programs are 

generally stationary, fossil fuel-fired 

boilers and combustion turbines serving 

generators larger than 25 megawatts 

(MW) producing electricity for sale. 

Most of these affected sources are also 

subject to the Acid Rain Program (ARP). 

The information collection requirements 

under the CSAPR and Texas trading 

programs and the ARP substantially 

overlap and are fully integrated. The 

burden and costs of overlapping 

requirements are accounted for in the 

ARP ICR (OMB Control Number 2060– 

0258). Thus, this ICR accounts for 

information collection burden and costs 

under the CSAPR NOX Ozone Season 

Group 3 trading program that are 

incremental to the burden and costs 

already accounted for in both the ARP 

and CSAPR ICRs. 

For most sources already reporting 

data under the CSAPR NOX Ozone 

Season Group 3 or CSAPR NOX Ozone 

Group 2 trading programs, there would 

be no incremental burden or cost, as 

reporting requirements will remain 

identical. Certain sources with a 

common stack configuration and/or 

those that are large, coal-fired EGUs, 

will be subject to additional emission 

reporting requirements under the 

proposed rule. These sources will need 

to make a one-time monitoring plan and 

Data Acquisition and Handling System 

(DAHS) update to meet the additional 

reporting requirements. Remaining for 

assessment of incremental cost and 

burden are only those sources in the five 

states not currently reporting data under 

a CSAPR NOX Ozone Season program. 

Sources in Minnesota are already 

reporting data for the CSAPR NOX

Annual program with almost identical 

information collection requirements, 

requiring only a one-time monitoring 

plan and DAHS update. Most of the 

affected sources in Delaware, Nevada, 

Utah, and Wyoming are already 

reporting data as part of the Acid Rain 

Program, thus only requiring a 

monitoring plan and DAHS update as 

well. Four additional EGUs in Delaware 

already report data under SIP 

requirements adopted to meet the NOX

SIP Call and would face identical 

information requirements under this 

proposed rule. For the units that already 

report to EPA under the Acid Rain 

Program or the NOX SIP Call, with the 

exception of any one-time costs to 

update monitoring plans and DAHS, all 

information collection costs and burden 

are already reflected in the previously 

approved ICRs for those other rules 

(OMB Control Nos. 2060–0258 and 

2060–0445). 

In total, there are an estimated 16 

units in Delaware, Nevada, Utah, and 

Wyoming that do not already report data 

to EPA according to 40 CFR part 75 and 

that would need to implement one of 

the Part 75 monitoring methodologies 

including certification of monitoring 

systems or implementation of the low 

mass emissions methodology. These 

units would also require monitoring 

plan and DAHS updates. Of these 

sixteen units, two units would be 

expected to adopt low mass emissions 

(LME) as the monitoring method, 

thirteen would be expected to adopt 

Appendix D monitoring methods, and 

one would be expected to adopt CEMS 

monitoring methods. 

Respondents/affected entities: 

Industry respondents are stationary, 

fossil fuel-fired boilers and combustion 

turbines serving electricity generators 

subject to the CSAPR and Texas trading 

programs, as well as non-source entities 

voluntarily participating in allowance 

trading activities. Potential state 

respondents are states that can elect to 

submit state-determined allowance 

allocations for sources located in their 

states. 

Respondent’s obligation to respond: 

Industry respondents: Voluntary and 

mandatory (Sections 110(a) and 301(a) 

of the Clean Air Act). 

Estimated number of respondents: 

EPA estimates that there would be 188 

industry respondents. 

Frequency of response: On occasion, 

quarterly, and annually. 

Total estimated additional burden: 

1,834 hours (per year). Burden is 

defined at 5 CFR 1320.03(b). 

Total estimated additional cost: 

$396,520 (per year); includes $210,571 

annualized capital or operation & 

maintenance costs. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 


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OMB’s Office of Information and 

Regulatory Affairs via email to OIRA_

submission@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than May 6, 2022. The EPA will 

respond to any ICR-related comments in 

the final rule. 

2. Information Collection Request for 

Non-Electric Generating Units 

The information collection activities 

in this proposed rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the PRA. The Information Collection 

Request (ICR) document that the EPA 

prepared has been assigned EPA ICR 

number 2705.01. The EPA has filed a 

copy of the non-EGU ICR in the docket 

for this rule, and it is briefly 

summarized here. 

ICR No. 2705.01 is a new request and 

it addresses the burden associated with 

new regulatory requirements under the 

proposed rule. Owners and operators of 

certain non-Electric Generating Unit 

(non-EGU) industry stationary sources 

will potentially modify or install new 

emission controls and associated 

monitoring systems to meet the nitrogen 

oxides (NOX) emission limits of this 

proposed rule. The burden in this ICR 

reflects the new monitoring, calibrating, 

recordkeeping, reporting and testing 

activities required by industry and the 

administrative review conducted by the 

states of the associated industry 

activities. This information is being 

collected to assure compliance with the 

proposed rule. In accordance with the 

Clean Air Act Amendments of 1990, any 

monitoring information to be submitted 

by sources is a matter of public record. 

Information received and identified by 

owners or operators as confidential 

business information (CBI) and 

approved as CBI by EPA, in accordance 

with Title 40, Chapter 1, Part 2, Subpart 

B, shall be maintained appropriately 

(see 40 CFR 2; 41 FR 36902, September 

1, 1976; amended by 43 FR 39999, 

September 8, 1978; 43 FR 42251, 

September 28, 1978; 44 FR 17674, 

March 23, 1979). 

Respondents/affected entities: The 

respondents/affected entities are the 

owners/operators of certain non-EGU 

industry sources in the following 

industry sectors: Furnaces in Glass and 

Glass Product Manufacturing; boilers 

and furnaces in Iron and Steel Mills and 

Ferroalloy Manufacturing; kilns in 

Cement and Cement Product 

Manufacturing; reciprocating internal 

combustion engines in Pipeline 

Transportation of Natural Gas; and highemitting equipment and large boilers in 

Basic Chemical Manufacturing, 

Petroleum and Coal Products 

Manufacturing, and Pulp, Paper, and 

Paperboard Mill. 

Respondent’s obligation to respond: 

Voluntary and mandatory. (Sections 

110(a) and 301(a) of the Clean Air Act). 

All data that is recorded or reported by 

respondents is required by the proposed 

rule, titled ‘‘Federal Implementation 

Plan Addressing Regional Ozone 

Transport for the 2015 Primary Ozone 

National Ambient Air Quality Standard: 

Transport Obligations for non-Electric 

Generating Units’’. 

Estimated number of respondents: 

489. 

Frequency of response: The specific 

frequency for each information 

collection activity within the non-EGU 

ICR is shown at the end of the ICR 

document in the Tables 1–11. In 

general, the frequency varies across the 

monitoring, recordkeeping, and 

reporting activities. Some recordkeeping 

such as work plan preparation is a onetime activity whereas engine 

maintenance recordkeeping is 

conducted quarterly. Reporting 

frequency is on a quarterly and semiannual basis. 

Total estimated burden: 51,654 hours 

(per year). Burden is defined at 5 CFR 

1320.3(b). 

Total estimated cost: $11,450,000 

(average per year); includes $5,467,000 

annualized capital or operation & 

maintenance costs. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

Submit your comments on the 

Agency’s need for this information from 

the EGU ICR and non-EGU ICR, the 

accuracy of the provided burden 

estimates and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to OIRA_

submission@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than May 6, 2022. The EPA will 

respond to any ICR-related comments in 

the final rule. 

C. Regulatory Flexibility Act (RFA) 

The EPA certifies that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities under the 

Regulatory Flexibility Act (RFA). The 

Regulatory Flexibility Act (5 U.S.C. 601 

et seq.), as amended by the Small 

Business Regulatory Enforcement 

Fairness Act (Pub. L. 104–121), provides 

that whenever an agency is required to 

publish a general notice of proposed 

rulemaking, it must prepare and make 

available an initial regulatory flexibility 

analysis, unless it certifies that the 

proposed rule, if promulgated, will not 

have a significant economic impact on 

a substantial number of small entities (5 

U.S.C. 605(b)). Small entities include 

small businesses, small organizations, 

and small governmental jurisdictions. 

In 2026, EPA identified 34 small 

entities affected by the proposed rule, 

and of these 6 small entities may 

experience costs of greater than 1 

percent of revenues. Of the 6 small 

entities projected to have costs greater 

than 1 percent of revenues, two of them 

operate in cost-of-service regions and 

would generally be able to pass any 

increased costs along to rate-payers. In 

EPA’s modeling, most of the cost 

impacts for these small entities and 

their associated units are driven by 

lower electricity generation relative to 

the base case baseline. Specifically, four 

units reduce their generation by 

significant amounts, driving the bulk of 

the costs for all small entities. Finally, 

EPA’s decision to exclude units smaller 

than 25 MW capacity from the proposed 

FIP, and exclusion of uncontrolled units 

smaller than 100 MW from backstop 

emission rate limits has already 

significantly reduced the burden on 

small entities by reducing the number of 

affected small entity-owned units. 

Further, in 2026 for non-EGUs, there are 

five small entities, and one small entity 

is estimated to have a cost-to-sales 

impact of 1.3 percent of their revenues. 

The EPA has determined that an 

insignificant number of small entities 

potentially affected by the proposed rule 

will have compliance costs greater than 

1 percent of annual revenues during the 

compliance period. EPA has concluded 

that there will be no significant 

economic impact on a substantial 

number of small entities (No SISNOSE) 

for this proposed rule overall. Details of 

this analysis are presented in Chapter 6 

of the RIA, which is in the public 

docket. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This proposed action does not contain 

an unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and will not significantly or 

uniquely affect small governments. Note 


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that we expect the proposed rule to 

potentially have an impact on only one 

category of government-owned entities 

(municipality-owned entities). This 

analysis does not examine potential 

indirect economic impacts associated 

with the proposed rule, such as 

employment effects in industries 

providing fuel and pollution control 

equipment, or the potential effects of 

electricity price increases on 

government entities. For more 

information on the estimated impact on 

government entities, refer to the RIA, 

which is in the public docket. 

E. Executive Order 13132: Federalism 

This proposed action does not have 

federalism implications. If finalized, 

this proposed action will not have 

substantial direct effects on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This proposed action has tribal 

implications. However, it would neither 

impose substantial direct compliance 

costs on federally recognized tribal 

governments, nor preempt tribal law. 

The EPA proposes to make a finding 

that interstate transport of ozone 

precursor emissions from 26 upwind 

states (Alabama, Arkansas, California, 

Delaware, Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, 

Minnesota, Mississippi, Missouri, 

Nevada, New Jersey, New York, Ohio, 

Oklahoma, Pennsylvania, Tennessee, 

Texas, Utah, Virginia, West Virginia, 

Wisconsin, and Wyoming) is 

significantly contributing to downwind 

nonattainment or interfering with 

maintenance of the 2015 ozone NAAQS 

in other states, based on projected 

nitrogen oxides (NOX) emissions in the 

2023 ozone season. EPA is proposing to 

issue FIP requirements to eliminate 

interstate transport of ozone precursors 

from these 26 states that significantly 

contributes to nonattainment or 

interferes with maintenance of the 

NAAQS in other states. Under CAA 

section 301(d)(4), EPA proposes to 

extend FIP requirements to apply in 

Indian country located within the 

upwind geography of the proposed rule, 

including Indian reservation lands and 

other areas of Indian country over 

which EPA or a tribe has demonstrated 

that a tribe has jurisdiction. EPA’s 

proposed extension is described further 

above in Section IV.C.2., Application of 

Rule in Indian Country and Necessary 

or Appropriate Finding. EPA proposes 

that all existing and new EGU and nonEGU sources that are located in the 

301(d) FIP areas within the geographic 

boundaries of the covered states, and 

which would be subject to this rule if 

located within areas subject to state 

CAA planning authority, should be 

included in this rule. This proposed 

action has tribal implication because of 

the proposed extension of FIP 

requirements into Indian country and 

this proposed rule may have additional 

tribal implications if a new affected 

EGU or non-EGU is built in Indian 

country. To EPA’s knowledge, only one 

existing EGU or non-EGU source is 

located within the 301(d) FIP areas: The 

Bonanza Power Plant, an EGU source, 

located on the Uintah and Ouray 

Reservation, geographically located 

within the borders of Utah. In general, 

tribes have a vested interest in how this 

proposed rule would affect air quality. 

In the Revised CSAPR Update, EPA 

established default procedures for 

allocating CSAPR NOX Ozone Season 

Group 3 allowances (‘‘Group 3 

allowances’’) in amounts equal to each 

state emissions budget for each control 

period among the sources in the state for 

use in complying with the Group 3 

trading program. Under the current 

Group 3 trading programs, reserved 

allowances are made available generally 

(but not exclusively 348) to ‘‘new’’ 

units—which for purposes of the 

Revised CSAPR Update means units 

commencing commercial operation on 

or after January 1, 2019—through a 

‘‘new unit set-aside’’ established for 

qualifying units in each state and, if 

areas of Indian country exist within the 

state’s borders, a separate ‘‘Indian 

country new unit set-aside’’ for 

qualifying units in such Indian country. 

In this rulemaking, EPA is proposing 

revisions to each step of the three-step 

allocation process to better address 

units in Indian country and to better 

coordinate the unit-level allocation 

process with the proposed dynamic 

budget-setting process. 

The EPA hosted an environmental 

justice webinar on October 26, 2021, 

that was attended by state regulatory 

authorities, environmental groups, 

federally recognized tribes, and small 

business stakeholders. The EPA will 

also continue to consult with the 

government of the Ute Indian Tribe of 

the Uintah and Ouray Reservation and 

plans to further consult with any other 

tribal officials under the EPA Policy on 

Consultation and Coordination with 

Indian Tribes early in the process of 

developing this proposed regulation to 

solicit meaningful and timely input into 

its development. The EPA plans to issue 

tribal consultation letters addressed to 

574 tribes in February 2022 after the 

proposed rule is signed. The EPA will 

likely facilitate an additional tribal 

consultation through a webinar before 

finalizing this proposed rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 as applying only to those 

regulatory actions that concern 

environmental health or safety risks that 

the EPA has reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it implements a previously 

promulgated health-based federal 

standard. This action’s health and risk 

assessments are contained in Chapter 5 

of this RIA. The EPA believes that the 

ozone-related benefits, PM2.5-related 

benefits, and CO2-related benefits from 

this proposed rule will further improve 

children’s health. Additionally, the 

ozone exposure analysis in Chapter 7 of 

the RIA suggests that nationally, 

children (ages 0–17) will experience at 

least as great a reduction in ozone 

exposures as adults (ages 18–64) in 2023 

and 2026 under all regulatory 

alternatives of this proposed 

rulemaking. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

This action is not a ‘‘significant 

energy action’’ because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

EPA has prepared a Statement of Energy 

Effects for the proposed regulatory 

control alternative as follows. The 

Agency estimates a 1 percent change in 

retail electricity prices on average across 

the contiguous U.S. in 2025, a 7.8 

percent reduction in coal-fired 

electricity generation, a 0.15 percent 

increase in natural gas-fired electricity 

generation, and a 3.8 percent increase in 

renewable electricity generation in 2025 

as a result of this proposed rule. EPA 

projects that utility power sector 

delivered natural gas prices will change 

by less than 1 percent in 2025. Details 

of the estimated energy effects are 

presented in Chapter 4 of the RIA, 

which is in the public docket. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This proposed rulemaking does not 

involve technical standards. 


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349 59 FR 7629, February 16, 1994. 

350 In proposing to invoke the exception by 

making and publishing a finding that this final 

action is based on a determination of nationwide 

scope or effect, the Administrator is taking into 

account a number of policy considerations, 

including his judgment balancing the benefit of 

obtaining the D.C. Circuit’s authoritative centralized 

review versus allowing development of the issue in 

other contexts and the best use of agency resources. 

351 In the report on the 1977 Amendments that 

revised section 307(b)(1) of the CAA, Congress 

noted that the Administrator’s determination that 

the ‘‘nationwide scope or effect’’ exception applies 

would be appropriate for any action that has a 

scope or effect beyond a single judicial circuit. See 

H.R. Rep. No. 95–294 at 323, 324, reprinted in 1977 

U.S.C.C.A.N. 1402–03. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes that this action does 

not have disproportionately high and 

adverse human health or environmental 

effects on minority populations, lowincome populations and/or indigenous 

peoples, as specified in Executive Order 

12898.349 The documentation for this 

decision is contained in Section VIII. 

Environmental Justice Analytical 

Considerations and Stakeholder 

Outreach and Engagement of this 

Proposed rule and in Chapter 7, 

Environmental Justice Impacts of the 

RIA, which is in the public document. 

The RIA was prepared under E.O. 12866 

Regulatory Planning and Review for this 

proposed rule. While the ozone 

exposure assessment was subject to 

several limitations, also described in 

Chapter 7 of the RIA, overall, ozone 

concentrations under the proposal, more 

stringent, and less stringent alternatives 

are predicted to impact demographic 

groups very similarly in both future 

years and across both EGUs and nonEGUs. 

Therefore, regarding ozone 

concentrations, EPA does not find 

evidence of meaningful environmental 

justice concerns associated with ozone 

concentrations after imposition of the 

proposed regulatory action or 

alternatives under consideration. We 

also do not find evidence that any 

potential environmental justice 

concerns related to ozone would be 

meaningfully exacerbated in the 

regulatory alternatives under 

consideration, compared to the baseline. 

Importantly, the action described in this 

proposed rule is expected to lower 

ozone in many areas, including residual 

ozone nonattainment areas, and thus 

mitigate some pre-existing health risks 

of ozone across all populations 

evaluated. 

In addition, the EPA provided the 

public, including those communities 

disproportionately impacted by the 

burdens of pollution, opportunities for 

meaningful engagement with the EPA 

on this action. A summary of outreach 

activities conducted by the Agency and 

what was heard from communities is 

provided in section VIII of this proposed 

rule. 

K. Determinations Under CAA Section 

307(b)(1) and (d) 

Section 307(b)(1) of the CAA governs 

judicial review of final actions by the 

EPA. This section provides, in part, that 

petitions for review must be filed in the 

United States Court of Appeals for the 

District of Columbia Circuit: (i) When 

the agency action consists of ‘‘nationally 

applicable regulations promulgated, or 

final action taken, by the 

Administrator,’’ or (ii) when such action 

is locally or regionally applicable, but 

‘‘such action is based on a 

determination of nationwide scope or 

effect and if in taking such action the 

Administrator finds and publishes that 

such action is based on such a 

determination.’’ For locally or regionally 

applicable final actions, the CAA 

reserves to EPA complete discretion 

whether to invoke the exception in (ii). 

This proposed action, if finalized, 

would be ‘‘nationally applicable’’ 

within the meaning of CAA section 

307(b)(1). In the alternative, to the 

extent a court finds this action to be 

locally or regionally applicable, the 

Administrator proposes to exercise the 

complete discretion afforded to him 

under the CAA to make and publish a 

finding that this action is based on a 

determination of ‘‘nationwide scope or 

effect’’ within the meaning of CAA 

section 307(b)(1).350

This proposed action, if finalized, will 

implement the good neighbor provision 

in 26 states, spanning 8 EPA regions and 

10 federal judicial circuits. The 

proposed action applies a uniform, 

nationwide analytical method and 

interpretation of CAA section 

110(a)(2)(D)(i)(I) across these states, and 

the proposed rule is based on a common 

core of legal, technical, and policy 

determinations (as explained in further 

detail in the following paragraph). For 

these reasons, this proposed action is 

nationally applicable. 

Alternatively, for these same reasons, 

the Administrator is exercising the 

discretion afforded to him by the CAA 

and hereby finds that this proposed 

action is based on multiple 

determinations of nationwide scope or 

effect for purposes of CAA section 

307(b)(1).351 Specifically, the proposed 

rule is based on a common core of 

statutory and case law analysis, factual 

findings, and policy determinations 

concerning the transport of ozoneprecursor pollutants from the different 

states subject to it, as well as the 

impacts of those pollutants and the 

impacts of options to address those 

pollutants in yet other states. In this 

proposed action, EPA is applying its 4- 

step analytic framework to implement 

the good neighbor provision across 

these states, using a consistent set of 

policy and analytical determinations. 

The proposed determinations include a 

nationally consistent definition of 

receptors at Step 1 and findings 

identifying downwind nonattainment 

and maintenance receptors; the 

application of a nationally consistent 

contribution threshold at Step 2 to 

determine which states are linked to 

those receptors and should be further 

evaluated at Step 3; the use of a 

nationally consistent multi-factor test at 

Step 3 to determine which upwind-state 

contributions to nonattainment and 

maintenance receptors are ‘‘significant’’ 

and must be eliminated; and the 

proposed implementation at Step 4 of a 

nationally consistent set of emissions 

control strategies through emissions 

budgets and an integrated interstate 

emissions trading program for EGUs, a 

nationally consistent set of other 

compliance requirements for EGUs, and 

a nationally consistent set of enforceable 

emissions limits and associated 

compliance requirements for certain 

non-EGU sources in several industrial 

sectors across 23 states. Finally, the 

technical, scientific, and engineering 

information in support of these 

proposed determinations relies on a 

nationally consistent set of air quality 

modeling analyses and other nationally 

consistent analytical methods, as set 

forth elsewhere in this proposed rule 

and in the relevant supporting 

documents in the docket for this 

proposed rule. 

Therefore, pursuant to CAA section 

307(b), any petitions for review of this 

action, if and when it is finalized, must 

be filed in the D.C. Circuit within 60 

days from the date such final action is 

published in the Federal Register. 

This action is subject to the 

provisions of section 307(d). CAA 

section 307(d)(1)(B) provides that 

section 307(d) applies to, among other 

things, ‘‘the promulgation or revision of 

an implementation plan by the 

Administrator under [CAA section 

110(c)].’’ 42 U.S.C. 7407(d)(1)(B). This 

action, among other things, proposes 

new federal implementation plans 

pursuant to the authority of section 

110(c). To the extent any portion of this 

rulemaking, if finalized, is not expressly 

identified under section 307(d)(1)(B), 


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the Administrator determines that the 

provisions of section 307(d) apply to 

such final action. See CAA section 

307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine’’). 

List of Subjects 

40 CFR Part 52 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen oxides, Ozone, Particulate 

matter, Sulfur dioxide. 

40 CFR Part 75 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Continuous 

emission monitoring, Electric power 

plants, Incorporation by reference, 

Nitrogen oxides, Ozone, Particulate 

matter, Reporting and recordkeeping 

requirements, Sulfur dioxide. 

40 CFR Part 78 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Electric power 

plants, Nitrogen oxides, Ozone, 

Particulate matter, Sulfur dioxide. 

40 CFR Part 97 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Electric power 

plants, Nitrogen oxides, Ozone, 

Particulate matter, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

Michael Regan, 

Administrator. 

For the reasons stated in the 

preamble, parts 52, 75, 78, and 97 of 

title 40 of the Code of Federal 

Regulations are proposed to be amended 

as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart A—General Provisions 

■ 2. Amend § 52.38 by: 

■ a. In paragraph (a)(1), removing 

‘‘(NOX), except’’ and adding in its place 

‘‘(NOX) for sources meeting the 

applicability criteria set forth in that 

subpart, except’’; 

■ b. In paragraph (a)(4) introductory 

text, removing ‘‘State’s sources, and’’ 

and adding in its place ‘‘State, and’’; 

■ c. In table 1 to paragraph (a)(4)(i)(B), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ d. In paragraph (a)(5) introductory 

text, removing ‘‘State (but not sources in 

any Indian country within the borders 

of the State), regulations’’ and adding in 

its place ‘‘State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority, 

regulations’’; 

■ e. In table 2 to paragraph (a)(5)(i)(B), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ f. In paragraph (a)(5)(iv), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ g. In paragraph (a)(5)(v), removing 

‘‘Indian country within the borders of 

the State, the’’ and adding in its place 

‘‘areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, the’’; 

■ h. Revising paragraphs (a)(6) and 

(a)(7)(ii); 

■ i. In paragraph (a)(8)(iii), removing 

‘‘State (but not sources in any Indian 

country within the borders of the 

State):’’ and adding in its place ‘‘State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority:’’; 

■ j. In paragraph (b)(1), removing ‘‘year), 

except’’ and adding in its place ‘‘year) 

for sources meeting the applicability 

criteria set forth in those subparts, 

except’’; 

■ k. Redesignating paragraphs (b)(2)(i) 

and (ii)as paragraphs (b)(2)(i)(A) and (B), 

respectively, redesignating paragraphs 

(b)(2)(iii) and (iv) as paragraphs 

(b)(2)(ii)(A) and (B), respectively, and 

redesignating paragraph (b)(2)(v) as 

paragraph (b)(2)(iii)(A); 

■ l. In newly redesignated paragraph 

(b)(2)(ii)(A), removing ‘‘Alabama, 

Arkansas, Iowa, Kansas, Mississippi, 

Missouri, Oklahoma, Tennessee, Texas, 

and Wisconsin.’’ and adding in its place 

‘‘Iowa and Kansas.’’; 

■ m. Adding paragraphs (b)(2)(ii)(C) and 

(b)(2)(iii)(B) and (C); 

■ n. In paragraph (b)(3) introductory 

text, removing ‘‘or (ii)’’; 

■ o. Revising paragraph (b)(4) 

introductory text; 

■ p. In table 3 to paragraph (b)(4)(ii)(B), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ q. Revising paragraph (b)(5) 

introductory text; 

■ r. In table 4 to paragraph (b)(5)(ii)(B), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ s. In paragraph (b)(5)(v), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ t. In paragraph (b)(5)(vi), removing 

‘‘Indian country within the borders of 

the State, the’’ and adding in its place 

‘‘areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, the’’; 

■ u. In paragraph (b)(7) introductory 

text, removing ‘‘(b)(2)(iii) or (iv)’’ and 

adding in its place ‘‘(b)(2)(ii)’’; 

■ v. Revising paragraph (b)(8) 

introductory text; 

■ w. In paragraph (b)(8)(i), adding 

‘‘and’’ after the semicolon; 

■ x. Removing and reserving paragraph 

(b)(8)(ii); 

■ y. Revising paragraph (b)(8)(iii)(A); 

■ z. In table 5 to paragraph (b)(8)(iii)(B), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ aa. In paragraph (b)(8)(iv), removing 

‘‘(b)(8)(i), (ii), or (iii)’’ and adding in its 

place ‘‘(b)(8)(i) or (iii)’’ each time it 

appears; 

■ bb. Revising paragraph (b)(9) 

introductory text; 

■ cc. Removing and reserving paragraph 

(b)(9)(ii); 

■ dd. Revising paragraph (b)(9)(iii)(A); 

■ ee. In table 6 to paragraph 

(b)(9)(iii)(B), revising the entry for ‘‘2025 

and any year thereafter’’; 

■ ff. In paragraph (b)(9)(vi), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ gg. Revising paragraph (b)(9)(vii); 

■ hh. In paragraph (b)(9)(viii), removing 

‘‘(b)(9)(i), (ii), or (iii)’’ and adding in its 

place ‘‘(b)(9)(i) or (iii)’’; 

■ ii. Revising paragraphs (b)(10) 

introductory text, (b)(10)(i) and (ii), 

(b)(10)(v)(A) and (B), (b)(11) 

introductory text, (b)(11)(iii) 

introductory text, (b)(11)(iii)(A) 

introductory text, and (b)(11)(iii)(B); 

■ jj. Removing and reserving paragraph 

(b)(11)(iii)(C); 

■ kk. Revising paragraph (b)(11)(iii)(D); 

■ ll. In paragraph (b)(11)(iv), removing 

‘‘paragraphs (b)(11)(iii)(B) and (C)’’ and 

adding in its place ‘‘paragraph 

(b)(11)(iii)(B)’’; 

■ mm. Revising paragraphs (b)(12) 

introductory text, (b)(12)(iii) 

introductory text, (b)(12)(iii)(A) 

introductory text, and (b)(12)(iii)(B); 

■ nn. Removing and reserving 

paragraph (b)(12)(iii)(C); 

■ oo. Revising paragraphs (b)(12)(iii)(D) 

and (b)(12)(vi) and (vii); 

■ pp. In paragraph (b)(12)(viii), 

removing ‘‘paragraphs (b)(12)(iii)(B) and 

(C)’’ and adding in its place ‘‘paragraph 

(b)(12)(iii)(B)’’; 


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■ qq. Revising paragraphs (b)(13) 

introductory text and (b)(13)(i); 

■ rr. In paragraph (b)(13)(ii), removing 

‘‘(b)(9)(ii) or’’; 

■ ss. In paragraph (b)(14)(i)(F), removing 

‘‘§ 97.825(b)’’ and adding in its place 

‘‘§§ 97.806(c)(2) and (3) and 97.825(b)’’; 

■ tt. In paragraph (b)(14)(i)(G), removing 

‘‘§ 97.826(e)’’ and adding in its place 

‘‘§ 97.826(f)’’; 

■ uu. Revising paragraphs (b)(14)(ii) and 

(b)(14)(iii) introductory text; 

■ vv. In paragraph (b)(14)(iii)(D), 

removing ‘‘and’’ after the semicolon; 

■ ww. In paragraph (b)(14)(iii)(E), 

removing ‘‘(b)(2)(iv) of this section).’’ 

and adding in its place ‘‘(b)(2)(ii)(B) of 

this section);’’; 

■ xx. Adding paragraphs (b)(14)(iii)(F) 

and (G); 

■ yy. In paragraph (b)(15)(iii), removing 

‘‘State (but not sources in any Indian 

country within the borders of the 

State):’’ and adding in its place ‘‘State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority:’’; 

■ zz. In paragraph (b)(16)(i)(B), 

removing ‘‘§ 97.804(a) and (b) or’’; 

■ aaa. Revising paragraph (b)(16)(i)(C); 

■ bbb. Redesignating paragraph 

(b)(16)(ii) as paragraph (b)(16)(ii)(A), 

and in the newly redesignated 

paragraph, removing ‘‘(b)(2)(iv)’’ and 

adding in its place ‘‘(b)(2)(ii)(B)’’; 

■ ccc. Adding paragraph (b)(16)(ii)(B); 

and 

■ ddd. Revising paragraphs (b)(17)(i) 

through (iii). 

The revisions and additions read as 

follows: 

§ 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 CSAPR NOX annual allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(5) * * * 

(i) * * * 

(B) * * * 

TABLE 2 TO PARAGRAPH (a)(5)(i)(B) 

Year of the control period for which CSAPR NOX annual allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(6) Withdrawal of CSAPR FIP 

provisions relating to NOX annual 

emissions. Except as provided in 

paragraph (a)(7) of this section, 

following promulgation of an approval 

by the Administrator of a State’s SIP 

revision as correcting the SIP’s 

deficiency that is the basis for the 

CSAPR Federal Implementation Plan set 

forth in paragraphs (a)(1), (a)(2)(i), and 

(a)(3) and (4) of this section for sources 

in the State and Indian country within 

the borders of the State, the provisions 

of paragraph (a)(2)(i) of this section will 

no longer apply to sources in the State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority, unless the 

Administrator’s approval of the SIP 

revision is partial or conditional, and 

will continue to apply to sources in 

areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, provided that if 

the CSAPR Federal Implementation 

Plan was promulgated as a partial rather 

than full remedy for an obligation of the 

State to address interstate air pollution, 

the SIP revision likewise will constitute 

a partial rather than full remedy for the 

State’s obligation unless provided 

otherwise in the Administrator’s 

approval of the SIP revision. 

(7) * * * 

(ii) Notwithstanding the provisions of 

paragraph (a)(6) of this section, if, at the 

time of any approval of a State’s SIP 

revision under this section, the 

Administrator has already started 

recording any allocations of CSAPR 

NOX Annual allowances under subpart 

AAAAA of part 97 of this chapter to 

units in the State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority for a 

control period in any year, the 

provisions of such subpart authorizing 

the Administrator to complete the 

allocation and recordation of such 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

* * * * * 

(b) * * * 

(2) * * * 

(ii) * * * 

(C) The provisions of subpart EEEEE 

of part 97 of this chapter apply to 

sources in each of the following States 

and Indian country located within the 

borders of such States with regard to 

emissions occurring in 2017 through 

2022 only, except as provided in 

paragraph (b)(14)(iii) of this section: 

Alabama, Arkansas, Mississippi, 

Missouri, Oklahoma, Tennessee, Texas, 

and Wisconsin. 

(iii) * * * 

(B) The provisions of subpart GGGGG 

of part 97 of this chapter apply to 

sources in each of the following States 

and Indian country located within the 

borders of such States with regard to 

emissions occurring in 2023 and each 

subsequent year: Alabama, Arkansas, 

Mississippi, Missouri, Oklahoma, 

Tennessee, Texas, and Wisconsin. 

(C) The provisions of subpart GGGGG 

of part 97 of this chapter apply to 

sources in each of the following States 

and Indian country located within the 

borders of such States with regard to 


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emissions occurring on and after 

[EFFECTIVE DATE OF FINAL RULE] 

and in each subsequent year: Delaware, 

Minnesota, Nevada, Utah, and 

Wyoming. 

* * * * * 

(4) Abbreviated SIP revisions 

replacing certain provisions of the 

federal CSAPR NOX Ozone Season 

Group 1 Trading Program. A State listed 

in paragraph (b)(2)(i)(A) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations replacing specified 

provisions of subpart BBBBB of part 97 

of this chapter for the State, and not 

substantively replacing any other 

provisions, as follows: 

* * * * * 

(ii) * * * 

(B) * * * 

TABLE 3 TO PARAGRAPH (b)(4)(ii)(B) 

Year of the control period for which CSAPR NOX ozone season Group 

1 allowances are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(5) Full SIP revisions adopting State 

CSAPR NOX Ozone Season Group 1 

Trading Programs. A State listed in 

paragraph (b)(2)(i)(A) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as correcting the deficiency in 

the SIP that is the basis for the CSAPR 

Federal Implementation Plan set forth in 

paragraphs (b)(1), (b)(2)(i), and (b)(3) 

and (4) of this section with regard to 

sources in the State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority, 

regulations that are substantively 

identical to the provisions of the CSAPR 

NOX Ozone Season Group 1 Trading 

Program set forth in §§ 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 CSAPR NOX ozone season Group 

1 allowances are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(8) Abbreviated SIP revisions 

replacing certain provisions of the 

federal CSAPR NOX Ozone Season 

Group 2 Trading Program. A State listed 

in paragraph (b)(2)(ii) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations replacing specified 

provisions of subpart EEEEE of part 97 

of this chapter for the State, and not 

substantively replacing any other 

provisions, as follows: 

* * * * * 

(iii) * * * 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of 

CSAPR NOX Ozone Season Group 2 

allowances for any such control period 

not exceeding the amount, under 

§§ 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 CSAPR NOX ozone season Group 

2 allowances are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(9) Full SIP revisions adopting State 

CSAPR NOX Ozone Season Group 2 

Trading Programs. A State listed in 

paragraph (b)(2)(ii) of this section may 

adopt and include in a SIP revision, and 

the Administrator will approve, as 

correcting the deficiency in the SIP that 

is the basis for the CSAPR Federal 

Implementation Plan set forth in 

paragraphs (b)(1), (b)(2)(ii), and (b)(7) 

and (8) of this section with regard to 

sources in the State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority, 

regulations that are substantively 

identical to the provisions of the CSAPR 

NOX Ozone Season Group 2 Trading 

Program set forth in §§ 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 


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§§ 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 CSAPR NOX ozone season Group 

2 allowances are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(vii) Provided that, if and when any 

covered unit is located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority, the Administrator may 

modify his or her approval of the SIP 

revision to exclude the provisions in 

§§ 97.802 (definitions of ‘‘common 

designated representative’’, ‘‘common 

designated representative’s assurance 

level’’, and ‘‘common designated 

representative’s share’’), 97.806(c)(2), 

and 97.825 of this chapter and the 

portions of other provisions of subpart 

EEEEE of part 97 of this chapter 

referencing these sections and may 

modify any portion of the CSAPR 

Federal Implementation Plan that is not 

replaced by the SIP revision to include 

these provisions; and 

* * * * * 

(10) State-determined allocations of 

CSAPR NOX Ozone Season Group 3 

allowances for 2024. A State listed in 

paragraph (b)(2)(iii) of this section may 

adopt and include in a SIP revision, and 

the Administrator will approve, as 

CSAPR NOX Ozone Season Group 3 

allowance allocation provisions 

replacing the provisions in 

§ 97.1011(a)(1) of this chapter with 

regard to the State and the control 

period in 2024, a list of CSAPR NOX

Ozone Season Group 3 units and the 

amount of CSAPR NOX Ozone Season 

Group 3 allowances allocated to each 

unit on such list, provided that the list 

of units and allocations meets the 

following requirements: 

(i) All of the units on the list must be 

units that are in the State and areas of 

Indian country within the borders of the 

State subject to the State’s SIP authority 

and that commenced commercial 

operation before January 1, 2021; 

(ii) The total amount of CSAPR NOX

Ozone Season Group 3 allowance 

allocations on the list must not exceed 

the amount, under § 97.1010 of this 

chapter for the State and the control 

period in 2024, of the CSAPR NOX

Ozone Season Group 3 trading budget 

minus the sum of the new unit set-aside 

and Indian country existing unit setaside; 

* * * * * 

(v) * * * 

(A) By [EFFECTIVE DATE OF FINAL 

RULE], the State must notify the 

Administrator electronically in a format 

specified by the Administrator of the 

State’s intent to submit to the 

Administrator a complete SIP revision 

meeting the requirements of paragraphs 

(b)(10)(i) through (iv) of this section by 

September 1, 2023; and 

(B) The State must submit to the 

Administrator a complete SIP revision 

described in paragraph (b)(10)(v)(A) of 

this section by September 1, 2023. 

(11) Abbreviated SIP revisions 

replacing certain provisions of the 

federal CSAPR NOX Ozone Season 

Group 3 Trading Program. A State listed 

in paragraph (b)(2)(iii) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations replacing specified 

provisions of subpart GGGGG of part 97 

of this chapter for the State, and not 

substantively replacing any other 

provisions, as follows: 

* * * * * 

(iii) The State may adopt, as CSAPR 

NOX Ozone Season Group 3 allowance 

allocation or auction provisions 

replacing the provisions in 

§ 97.1011(a)(1) of this chapter with 

regard to the State and the control 

period in 2025 or any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions CSAPR NOX Ozone Season 

Group 3 allowances and may adopt, in 

addition to the definitions in § 97.1002 

of this chapter, one or more definitions 

that shall apply only to terms as used in 

the adopted CSAPR NOX Ozone Season 

Group 3 allowance allocation or auction 

provisions, if such methodology— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of 

CSAPR NOX Ozone Season Group 3 

allowances for any such control period 

not exceeding the amount, under 

§§ 97.1010 and 97.1021 of this chapter 

for the State and such control period, of 

the CSAPR NOX Ozone Season Group 3 

trading budget minus the sum of the 

new unit set-aside, the Indian country 

existing unit set-aside, and the amount 

of any CSAPR NOX Ozone Season 

Group 3 allowances already allocated 

and recorded by the Administrator, 

plus, if the State adopts regulations 

expanding applicability to additional 

units pursuant to paragraph (b)(11)(ii) of 

this section, an additional amount of 

CSAPR NOX Ozone Season Group 3 

allowances not exceeding the lesser of: 

* * * * * 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of CSAPR NOX Ozone Season 

Group 3 allowances for any such control 

period to any CSAPR NOX Ozone 

Season Group 3 units covered by 

§ 97.1011(a)(1) of this chapter, that the 

State or the permitting authority submit 

such allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of CSAPR NOX Ozone Season 

Group 3 allowances remaining in a setaside after completion of the allocations 

or auctions for which the set-aside was 

created) to the Administrator by June 1 

of the year before the year of such 

control period; and 

* * * * * 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraph (b)(11)(iii)(B) of this section, 

in the allocations submitted to the 

Administrator by such deadlines and 

does not provide for any change in any 

allocation determined and recorded by 

the Administrator under subpart 

GGGGG of part 97 of this chapter or 

§ 97.526(d) or § 97.826(d) or (e) of this 

chapter; 

* * * * * 

(12) Full SIP revisions adopting State 

CSAPR NOX Ozone Season Group 3 

Trading Programs. A State listed in 

paragraph (b)(2)(iii) of this section may 

adopt and include in a SIP revision, and 

the Administrator will approve, as 

correcting the deficiency in the SIP that 

is the basis for the CSAPR Federal 


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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 §§ 97.1002 through 

97.1035 of this chapter, except that the 

SIP revision: 

* * * * * 

(iii) May adopt, as CSAPR NOX Ozone 

Season Group 3 allowance allocation 

provisions replacing the provisions in 

§ 97.1011(a)(1) of this chapter with 

regard to the State and the control 

period in 2025 or any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions CSAPR NOX Ozone Season 

Group 3 allowances and that— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of 

CSAPR NOX Ozone Season Group 3 

allowances for any such control period 

not exceeding the amount, under 

§§ 97.1010 and 97.1021 of this chapter 

for the State and such control period, of 

the CSAPR NOX Ozone Season Group 3 

trading budget minus the sum of the 

new unit set-aside, the Indian country 

existing unit set-aside, and the amount 

of any CSAPR NOX Ozone Season 

Group 3 allowances already allocated 

and recorded by the Administrator, 

plus, if the State adopts regulations 

expanding applicability to additional 

units pursuant to paragraph (b)(12)(ii) of 

this section, an additional amount of 

CSAPR NOX Ozone Season Group 3 

allowances not exceeding the lesser of: 

* * * * * 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of CSAPR NOX Ozone Season 

Group 3 allowances for any such control 

period to any CSAPR NOX Ozone 

Season Group 3 units covered by 

§ 97.1011(a)(1) of this chapter, that the 

State or the permitting authority submit 

such allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of CSAPR NOX Ozone Season 

Group 3 allowances remaining in a setaside after completion of the allocations 

or auctions for which the set-aside was 

created) to the Administrator by June 1 

of the year before the year of such 

control period; and 

* * * * * 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraph (b)(12)(iii)(B) of this section, 

in the allocations submitted to the 

Administrator by such deadlines and 

does not provide for any change in any 

allocation determined and recorded by 

the Administrator under subpart 

GGGGG of part 97 of this chapter or 

§ 97.526(d) or § 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 

§§ 97.1002 through 97.1035 of this 

chapter and must not include the 

provisions in §§ 97.1011(a)(2), 97.1012, 

and 97.1021(g) through (j) of this 

chapter, all of which provisions will 

continue to apply under the portion of 

the CSAPR Federal Implementation 

Plan that is not replaced by the SIP 

revision; 

(vii) Provided that, if any covered unit 

is located in areas of Indian country 

within the borders of the State not 

subject to the State’s SIP authority 

before the Administrator’s approval of 

the SIP revision, the SIP revision must 

exclude the provisions in §§ 97.1002 

(definitions of ‘‘base CSAPR NOX Ozone 

Season Group 3 source’’, ‘‘base CSAPR 

NOX Ozone Season Group 3 unit’’, 

‘‘common designated representative’’, 

‘‘common designated representative’s 

assurance level’’, and ‘‘common 

designated representative’s share’’), 

97.1006(c)(2), and 97.1025 of this 

chapter and the portions of other 

provisions of subpart GGGGG of part 97 

of this chapter referencing these 

sections, and further provided that, if 

and when any covered unit is located in 

areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority after the 

Administrator’s approval of the SIP 

revision, the Administrator may modify 

his or her approval of the SIP revision 

to exclude these provisions and may 

modify any portion of the CSAPR 

Federal Implementation Plan that is not 

replaced by the SIP revision to include 

these provisions; and 

* * * * * 

(13) Withdrawal of CSAPR FIP 

provisions relating to NOX ozone season 

emissions; satisfaction of NOX SIP Call 

requirements. Following promulgation 

of an approval by the Administrator of 

a State’s SIP revision as correcting the 

SIP’s deficiency that is the basis for the 

CSAPR Federal Implementation Plan set 

forth in paragraphs (b)(1), (b)(2)(i), and 

(b)(3) and (4) of this section, paragraphs 

(b)(1), (b)(2)(ii), and (b)(7) and (8) of this 

section, or paragraphs (b)(1), (b)(2)(iii), 

and (b)(10) and (11) of this section for 

sources in the State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority— 

(i) Except as provided in paragraph 

(b)(14) of this section, the provisions of 

paragraph (b)(2)(i), (ii), or (iii) of this 

section, as applicable, will no longer 

apply to sources in the State and areas 

of Indian country within the borders of 

the State subject to the State’s SIP 

authority, unless the Administrator’s 

approval of the SIP revision is partial or 

conditional, and will continue to apply 

to sources in areas of Indian country 

within the borders of the State not 

subject to the State’s SIP authority, 

provided that if the CSAPR Federal 

Implementation Plan was promulgated 

as a partial rather than full remedy for 

an obligation of the State to address 

interstate air pollution, the SIP revision 

likewise will constitute a partial rather 

than full remedy for the State’s 

obligation unless provided otherwise in 

the Administrator’s approval of the SIP 

revision; and 

* * * * * 

(14) * * * 

(ii) Notwithstanding the provisions of 

paragraph (b)(13)(i) of this section, if, at 

the time of any approval of a State’s SIP 

revision under this section, the 

Administrator has already started 

recording any allocations of CSAPR 

NOX Ozone Season Group 1 allowances 

under subpart BBBBB of part 97 of this 

chapter, or allocations of CSAPR NOX

Ozone Season Group 2 allowances 

under subpart EEEEE of part 97 of this 

chapter, or allocations of CSAPR NOX

Ozone Season Group 3 allowances 

under subpart GGGGG of part 97 of this 

chapter, to units in the State and areas 

of Indian country within the borders of 

the State subject to the State’s SIP 

authority for a control period in any 

year, the provisions of such subpart 

authorizing the Administrator to 

complete the allocation and recordation 

of such allowances to such units for 

each such control period shall continue 

to apply, unless provided otherwise by 

such approval of the State’s SIP 

revision. 

(iii) Notwithstanding any 

discontinuation of the applicability of 

subpart BBBBB or EEEEE of part 97 of 

this chapter to the sources in a State and 

areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority with regard to emissions 

occurring in any control period 

pursuant to paragraph (b)(2)(i)(B), 

(b)(2)(ii)(B) or (C), or (b)(13)(i) of this 

section, the following provisions shall 

continue to apply with regard to all 

CSAPR NOX Ozone Season Group 1 

allowances and CSAPR NOX Ozone 

Season Group 2 allowances at any time 


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allocated for any control period to any 

source or other entity in the State and 

shall apply to all entities, wherever 

located, that at any time held or hold 

such allowances: 

* * * * * 

(F) The provisions of § 97.826(e) of 

this chapter (concerning the conversion 

of amounts of unused CSAPR NOX

Ozone Season Group 2 allowances 

allocated for control periods before 2023 

to different amounts of CSAPR NOX

Ozone Season Group 3 allowances); and 

(G) The provisions of § 97.811(e) of 

this chapter (concerning the recall of 

CSAPR NOX Ozone Season Group 2 

allowances equivalent in quantity and 

usability to all CSAPR NOX Ozone 

Season Group 2 allowances allocated for 

control periods after 2022 and recorded 

in the compliance accounts of sources 

in States listed in paragraph (b)(2)(ii)(C) 

of this section). 

* * * * * 

(16) * * * 

(i) * * * 

(C) For each of the following States, 

the Administrator has approved a SIP 

revision under paragraph (b)(9) of this 

section as correcting the SIP’s 

deficiency that is the basis for the 

CSAPR Federal Implementation Plan set 

forth in paragraphs (b)(1), (b)(2)(ii), and 

(b)(7) and (8) of this section with regard 

to sources in the State and areas of 

Indian country within the borders of the 

State subject to the State’s SIP authority: 

Alabama, Indiana, and Missouri. 

(ii) * * * 

(B) Notwithstanding any provision of 

subpart EEEEE of part 97 of this chapter 

or any State’s SIP, with regard to any 

State listed in paragraph (b)(2)(ii)(C) of 

this section and any control period that 

begins after December 31, 2022, the 

Administrator will not carry out any of 

the functions set forth for the 

Administrator in subpart EEEEE of part 

97 of this chapter, except §§ 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 § 97.1011(a)(1) 

of this chapter with regard to the State 

and the control period in 2024: [none]. 

(ii) For each of the following States, 

the Administrator has approved a SIP 

revision under paragraph (b)(11) of this 

section as replacing the CSAPR NOX

Ozone Season Group 3 applicability 

provisions in § 97.1004(a) and (b) or 

§ 97.1004(a)(1) and (2) of this chapter or 

the CSAPR NOX Ozone Season Group 2 

allowance allocation provisions in 

§ 97.1011(a)(1) of this chapter with 

regard to the State and the control 

period in 2025 or any subsequent year: 

[none]. 

(iii) For each of the following States, 

the Administrator has approved a SIP 

revision under paragraph (b)(12) of this 

section as correcting the SIP’s 

deficiency that is the basis for the 

CSAPR Federal Implementation Plan set 

forth in paragraphs (b)(1), (b)(2)(iii), and 

(b)(10) and (11) of this section with 

regard to sources in the State and areas 

of Indian country within the borders of 

the State subject to the State’s SIP 

authority: [none]. 

■ 3. Amend § 52.39 by: 

■ a. In paragraph (a), removing ‘‘(SO2), 

except’’ and adding in its place ‘‘(SO2) 

for sources meeting the applicability 

criteria set forth in those subparts, 

except’’; 

■ b. In paragraph (e) introductory text, 

removing ‘‘State’s sources, and’’ and 

adding in its place ‘‘State, and’’; 

■ c. In table 1 to paragraph (e)(1)(ii), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ d. In paragraph (f) introductory text, 

removing ‘‘State (but not sources in any 

Indian country within the borders of the 

State), regulations’’ and adding in its 

place ‘‘State and areas of Indian country 

within the borders of the State subject 

to the State’s SIP authority, 

regulations’’; 

■ e. In table 2 to paragraph (f)(1)(ii), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ f. In paragraph (f)(4), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ g. In paragraph (f)(5), removing 

‘‘Indian country within the borders of 

the State, the’’ and adding in its place 

‘‘areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, the’’; 

■ h. In paragraph (h) introductory text, 

removing ‘‘State’s sources, and’’ and 

adding in its place ‘‘State, and’’; 

■ i. In table 3 to paragraph (h)(1)(ii), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ j. In paragraph (i) introductory text, 

removing ‘‘State (but not sources in any 

Indian country within the borders of the 

State), regulations’’ and adding in its 

place ‘‘State and areas of Indian country 

within the borders of the State subject 

to the State’s SIP authority, 

regulations’’; 

■ k. In table 4 to paragraph (i)(1)(ii), 

revising the entry for ‘‘2025 and any 

year thereafter’’; 

■ l. In paragraph (i)(4), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ m. In paragraph (i)(5), removing 

‘‘Indian country within the borders of 

the State, the’’ and adding in its place 

‘‘areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, the’’; 

■ n. Revising paragraphs (j) and (k)(2); 

and 

■ o. In paragraphs (l)(3) and (m)(3), 

removing ‘‘State (but not sources in any 

Indian country within the borders of the 

State):’’ and adding in its place ‘‘State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority:’’. 

The revisions read as follows: 

§ 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 CSAPR SO2 Group 1 allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 


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* * * * * 

(f) * * * 

(i) * * * 

(ii) * * * 

TABLE 2 TO PARAGRAPH (f)(1)(ii) 

Year of the control period for which CSAPR SO2 Group 1 allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(h) * * * 

(1) * * * 

(ii) * * * 

TABLE 3 TO PARAGRAPH (h)(1)(ii) 

Year of the control period for which CSAPR SO2 Group 2 allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(i) * * * 

(1) * * * 

(ii) * * * 

TABLE 4 TO PARAGRAPH (i)(1)(ii) 

Year of the control period for which CSAPR SO2 Group 2 allowances 

are allocated or auctioned 

Deadline for submission of allocations or auction results 

to the Administrator 

*******

2025 and any year thereafter ................................................................... June 1 of the year before the year of the control period. 

* * * * * 

(j) Withdrawal of CSAPR FIP 

provisions relating to SO2 emissions. 

Except as provided in paragraph (k) of 

this section, following promulgation of 

an approval by the Administrator of a 

State’s SIP revision as correcting the 

SIP’s deficiency that is the basis for the 

CSAPR Federal Implementation Plan set 

forth in paragraphs (a), (b), (d), and (e) 

of this section or paragraphs (a), (c)(1), 

(g), and (h) of this section for sources in 

the State and Indian country within the 

borders of the State, the provisions of 

paragraph (b) or (c)(1) of this section, as 

applicable, will no longer apply to 

sources in the State and areas of Indian 

country within the borders of the State 

subject to the State’s SIP authority, 

unless the Administrator’s approval of 

the SIP revision is partial or conditional, 

and will continue to apply to sources in 

areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority, provided that if 

the CSAPR Federal Implementation 

Plan was promulgated as a partial rather 

than full remedy for an obligation of the 

State to address interstate air pollution, 

the SIP revision likewise will constitute 

a partial rather than full remedy for the 

State’s obligation unless provided 

otherwise in the Administrator’s 

approval of the SIP revision. 

(k) * * * 

(2) Notwithstanding the provisions of 

paragraph (j) of this section, if, at the 

time of any approval of a State’s SIP 

revision under this section, the 

Administrator has already started 

recording any allocations of CSAPR SO2

Group 1 allowances under subpart 

CCCCC of part 97 of this chapter, or 

allocations of CSAPR SO2 Group 2 

allowances under subpart DDDDD of 

part 97 of this chapter, to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of such 

subpart authorizing the Administrator to 

complete the allocation and recordation 

of such allowances to such units for 

each such control period shall continue 

to apply, unless provided otherwise by 

such approval of the State’s SIP 

revision. 

* * * * * 

■ 4. Add §§ 52.40 through 52.45 to read 

as follows: 

* * * * * 

Sec. 

52.40 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from sources not subject 

to the CSAPR ozone season trading 

program? 

52.41 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Pipeline 

Transportation of Natural Gas Industry? 

52.42 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Cement and 

Concrete Product Manufacturing 

Industry? 

52.43 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Iron and Steel 

Mills and Ferroalloy Manufacturing 

Industry? 


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52.44 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Glass and Glass 

Product Manufacturing Industry? 

52.45 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills Industries? 

* * * * * 

§ 52.40 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from sources not subject to 

the CSAPR ozone season trading program? 

(a) NOX ozone season emissions. This 

section establishes Federal 

Implementation Plan requirements for 

new and existing units in the industries 

specified in paragraph (b) of this section 

to eliminate significant contribution to 

nonattainment, or interference with 

maintenance, of the 2015 8-hour ozone 

National Ambient Air Quality Standards 

in other states pursuant to 42 U.S.C. 

7410(a)(2)(D)(i)(I). 

(b) General requirements (1) The NOX

emissions limitations and associated 

compliance requirements for the 

following listed source categories not 

subject to the CSAPR ozone season 

trading program constitute the Federal 

Implementation Plan provisions that 

relate to emissions of NOX during the 

ozone season (defined as May 1 through 

September 30 of a calendar year): 

§ 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 units in the Iron 

and Steel Mills and Ferroalloy 

Manufacturing Industry, § 52.44 for 

units in the Glass and Glass Product 

Manufacturing Industry, § 52.45 for 

boilers in Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, 

Paper, and Paperboard Mills. 

(2) The provisions of §§ 52.41 through 

52.45 of this part apply to sources 

located in each of the following States, 

including Indian country located within 

the borders of such States, beginning in 

the 2026 ozone season and in each 

subsequent ozone season: Arkansas, 

California, Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Michigan, 

Minnesota, Mississippi, Missouri, 

Nevada, New Jersey, New York, Ohio, 

Oklahoma, Pennsylvania, Texas, Utah, 

Virginia, West Virginia, Wisconsin, and 

Wyoming. 

(3) The owner or operator of an 

affected unit subject to the provisions of 

§§ 52.40 through 52.45 shall maintain 

files of all information (including all 

reports and notifications) required by 

these sections recorded in a form 

suitable and readily available for 

expeditious inspection and review. The 

files shall be retained for at least 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. At a minimum, 

the most recent 2 years of data shall be 

retained on site. The remaining 3 years 

of data may be retained off site. Such 

files may be maintained on microfilm, 

on a computer, on computer floppy 

disks, on magnetic tape disks, or on 

microfiche. 

§ 52.41 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Pipeline 

Transportation of Natural Gas Industry? 

(a) Definitions. All terms not defined 

herein shall have the meaning given 

them in the Act and in subpart A of part 

60. 

Affected unit means an engine 

meeting the applicability criteria of this 

section. 

Four stroke means any type of engine 

which completes the power cycle in two 

crankshaft revolutions, with intake and 

compression strokes in the first 

revolution and power and exhaust 

strokes in the second revolution. 

ISO conditions means 288 Kelvin 

(15 °C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Lean burn means any two-stroke or 

four-stroke spark ignited reciprocating 

internal combustion engine that does 

not meet the definition of a rich burn 

engine. 

Nameplate rating means the 

manufacturer’s design maximum 

capacity in horsepower (hp) at the 

installation site conditions. Starting 

from the completion of any physical 

change in the engine resulting in an 

increase in the maximum output (in hp) 

that the engine is capable of producing 

on a steady state basis and during 

continuous operation, such increased 

maximum output shall be as specified 

by the person conducting the physical 

change. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane) or non-hydrocarbons, 

composed of at least 70 percent methane 

by volume or that has a gross calorific 

value between 35 and 41 megajoules 

(MJ) per dry standard cubic meter (950 

and 1,100 Btu per dry standard cubic 

foot), that maintains a gaseous state 

under ISO conditions. Natural gas does 

not include the following gaseous fuels: 

Landfill gas, digester gas, refinery gas, 

sour gas, blast furnace gas, coal-derived 

gas, producer gas, coke oven gas, or any 

gaseous fuel produced in a process 

which might result in highly variable 

CO2 content or heating value. 

Natural gas-fired means that greater 

than or equal to 90% of the engine’s 

heat input, excluding recirculated or 

recuperated exhaust heat, is derived 

from the combustion of natural gas. 

Operator means any person who 

operates, controls, or supervises a 

natural gas-fired engine subject to this 

regulation and shall include, but not be 

limited to, any holding company, utility 

system, or plant manager of such natural 

gas-fired engine. 

Owner means any holder of any 

portion of the legal or equitable title in 

a natural gas-fired engine subject to this 

regulation. 

Pipeline transportation of natural gas 

means the movement of natural gas 

through an interconnected network of 

compressors and pipeline components, 

from field gathering networks near 

wellheads to end users, including: 

(i) The compressor and pipeline 

network used for field gathering of 

natural gas from the wellheads for 

delivery to either processing facilities or 

connections to pipelines used for 

intrastate or interstate transportation of 

the natural gas; and 

(ii) The compressor and pipeline 

network used to transport the natural 

gas from field gathering networks or 

processing facilities over a distance 

(intrastate or interstate) to and from 

storage facilities, to large natural gas 

end-users, and to distribution 

organizations that provide the natural 

gas to end-users. 

Reciprocating internal combustion 

engine means a reciprocating engine in 

which power, produced by heat and/or 

pressure that is developed in the engine 

combustion chambers by the burning of 

a mixture of air and fuel, is 

subsequently converted to mechanical 

work. 

Rich burn means any four-stroke 

spark ignited reciprocating internal 

combustion engine where the 

manufacturer’s recommended operating 

air/fuel ratio divided by the 

stoichiometric air/fuel ratio at full load 

conditions is less than or equal to 1.1. 

Internal combustion engines originally 

manufactured as rich burn engines but 

modified with passive emission control 

technology for nitrogen oxides (NOX) 

(such as pre-combustion chambers) will 

be considered lean burn engines. 

Existing internal combustion engines 

where there are no manufacturer’s 

recommendations regarding air/fuel 

ratio will be considered rich burn 

engines if the excess oxygen content of 


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the exhaust at full load conditions is 

less than or equal to 2 percent. 

Spark ignition means a reciprocating 

internal combustion engine utilizing a 

spark plug (or other sparking device) to 

ignite the air/fuel mixture and with 

operating characteristics significantly 

similar to the theoretical Otto 

combustion cycle. 

Stoichiometric means the theoretical 

air-to-fuel ratio required for complete 

combustion. 

Two stroke means a type of 

reciprocating internal combustion 

engine which completes the power 

cycle in a single crankshaft revolution 

by combining the intake and 

compression operations into one stroke 

(one-half revolution) and the power and 

exhaust operations into a second stroke. 

This system requires auxiliary exhaust 

scavenging of the combustion products 

and inherently runs lean (excess of air) 

of stoichiometry. 

(b) Applicability. You are subject to 

the requirements under this section if 

you own or operate a new or existing 

natural gas-fired spark ignition engine 

with a nameplate rating of 1,000 hp or 

greater that is used for pipeline 

transportation of natural gas and is 

located within any of the States listed in 

§ 52.40(a)(1)(ii), including Indian 

country located within the borders of 

any such State(s). 

(c) Emissions limitations. Beginning 

with the 2026 ozone season and in each 

ozone season thereafter, the following 

emissions limitations must be met. 

Compliance with the numerical 

emissions limitations established in this 

section is based on the average of three 

1-hour runs using the testing 

requirements and procedures in 

paragraph (d) of this section. 

(1) If you own or operate a natural gas 

fired four stroke rich burn spark ignition 

engine with a nameplate rating of 1,000 

hp or greater than you must meet a 

nitrogen oxides (NOX) emissions limits 

of 1.0 grams per hp-hour (g/hp-hr). 

(2) If you own or operate a natural gas 

fired four stroke lean burn spark 

ignition engine with a nameplate rating 

of 1,000 hp or greater than you must 

meet a NOX emissions limits of 1.5 g/hphr. 

(3) If you own or operate a natural gas 

fired two stroke lean spark ignition 

engine with a nameplate rating of 1,000 

hp or greater than you must meet a NOX

emissions limits of 3.0 g/hp-hr. 

(d) Testing and monitoring 

requirements (1) If you are an owner or 

operator of a natural gas fired spark 

ignition engine subject to a NOX

emissions limit under paragraph (b) of 

this section, you must keep a 

maintenance plan and records of 

conducted maintenance and must, to 

the extent practicable, maintain and 

operate the engine in a manner 

consistent with good air pollution 

control practice for minimizing 

emissions. 

(2) Performance Testing 

Requirements: 

(i) Engines that meet the certification 

requirements of § 60.4243(a) need not 

conduct any performance tests, 

consistent with the requirements of 40 

CFR part 60, subpart JJJJ. 

(ii) For non-certified engines, the 

following performance testing 

requirements apply: 

(A) New engines must conduct an 

initial performance test within six 

months of engine startup and conduct 

subsequent performance testing every 

six months thereafter to demonstrate 

compliance. 

(B) Existing engines must conduct an 

initial performance test within six 

months of becoming subject to an 

emissions limit under paragraph (b) of 

this section and conduct subsequent 

performance testing every six months 

thereafter to demonstrate compliance. 

(iii) Performance tests must be 

conducted in accordance with the 

applicable reference test methods of 40 

CFR part 60, appendix A, any 

alternative test method approved by 

EPA as of April 6, 2022 under 40 CFR 

59.104(f), 60.8(b)(3), 61.13(h)(1)(ii), 

63.7(e)(2)(ii), or 65.158(a)(2) and 

available at EPA’s website (https://

www.epa.gov/emc/broadly-applicableapproved-alternative-test-methods), or 

other methods and procedures approved 

by EPA through notice-and-comment 

rulemaking. 

(3) If a selective catalytic reduction 

(SCR) or non-selective catalytic 

reduction (NSCR) control device is used 

to reduce emissions: 

(i) Monitor the inlet temperature to 

the catalyst daily and conduct 

maintenance if the temperature is not 

within the observed inlet temperature 

range from the most recent performance 

test or the temperatures specified by the 

manufacturer if no performance test was 

required by this section. 

(ii) Measure the pressure drop across 

the catalyst monthly and conduct 

maintenance if the pressure drop is 

greater than 2 inches outside the 

baseline value established after each 

semiannual portable analyzer 

monitoring. 

(iii) Engines that are subject to 

catalyst temperatures and catalyst 

pressure drop monitoring requirements 

under 40 CFR part 63, subpart ZZZZ 

must satisfy the requirements of 

§ 52.41(d)(3). 

(4) If you are not using a SCR or NSCR 

control device to reduce emissions are 

required to install a continuous 

parameter monitoring system (CPMS). 

You must install, operate, and maintain 

each CPMS according to the 

requirements in paragraphs (d)(4)(i) 

through (vi) of this section. 

(i) You must prepare a site-specific 

monitoring plan that addresses the 

monitoring system design, data 

collection, and quality assurance and 

quality control elements outlined in 

paragraphs (d)(4)(i)(A) through (E) of 

this section. 

(A) The performance criteria and 

design specifications for the monitoring 

system equipment, including the sample 

interface, detector signal analyzer, and 

data acquisition and calculations. 

(B) Sampling interface (e.g., 

thermocouple) location such that the 

monitoring system will provide 

representative measurements. 

(C) Equipment performance 

evaluations, system accuracy audits, or 

other audit procedures. 

(D) Ongoing operation and 

maintenance procedures in accordance 

with the requirements of paragraph 

(d)(1) of this section. 

(E) Ongoing recordkeeping and 

reporting procedures in accordance with 

the requirements of paragraphs (e) and 

(f) of this section. 

(ii) Install, operate, and maintain each 

CPMS in continuous operation 

according to the procedures in your sitespecific monitoring plan. 

(iii) The CPMS must collect data at 

least once every 15 minutes. 

(iv) For a CPMS for measuring 

temperature range, the temperature 

sensor must have a minimum tolerance 

of 2.8 degrees Celsius (5 degrees 

Fahrenheit) or 1 percent of the 

measurement range, whichever is larger. 

(v) You must conduct the CPMS 

equipment performance evaluation, 

system accuracy audits, or other audit 

procedures specified in your sitespecific monitoring plan at least 

annually. 

(vi) You must conduct a performance 

evaluation of each CPMS in accordance 

with your site-specific monitoring plan. 

(e) Recordkeeping requirements (1) 

You must keep records of: 

(i) Performance tests conducted 

pursuant to § 52.41(d)(2), including the 

date, engine settings on the date of the 

test, and documentation of the methods 

and results of the testing. 

(ii) Catalyst monitoring required by 

§ 52.41(d)(3), if applicable, and any 

actions taken to address monitored 

values outside the temperature or 

pressure drop parameters, including the 

date and a description of actions taken. 


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(iii) Parameters monitored pursuant to 

your site-specific monitoring plan for 

your CPMS. 

(iv) Hours of operation on a daily 

basis. 

(v) Tuning, adjustments, or other 

combustion process adjustments and the 

date of the adjustment(s). 

(2) Any records required to be 

maintained by this section that are 

submitted electronically via the EPA’s 

Compliance and Emissions Data 

Reporting Interface (CEDRI) may be 

maintained in electronic format. This 

ability to maintain electronic copies 

does not affect the requirement for 

facilities to make records, data, and 

reports available upon request to the 

EPA as part of an on-site compliance 

evaluation. 

(f) Reporting requirements (1) Within 

60 days after the date of completing 

each performance test required by this 

section, you must submit the results of 

the performance test following the 

procedures specified in paragraphs 

(f)(1)(i) through (iii): 

(i) Data collected using test methods 

supported by the EPA’s Electronic 

Reporting Tool (ERT) as listed on the 

EPA’s ERT website (https://

www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert) 

at the time of the test. Submit the results 

of the performance test to the EPA via 

the CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section, 

which can be accessed through the 

EPA’s Central Data Exchange (CDX) 

(https://cdx.epa.gov/). The data must be 

submitted in a file format generated 

using the EPA’s ERT. Alternatively, you 

may submit an electronic file consistent 

with the extensible markup language 

(XML) schema listed on the EPA’s ERT 

website. 

(ii) Data collected using test methods 

that are not supported by the EPA’s ERT 

as listed on the EPA’s ERT website at 

the time of the test. The results of the 

performance test must be included as an 

attachment in the ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. Submit the ERT generated 

package or alternative file to the EPA via 

CEDRI. 

(iii) Confidential business information 

(CBI). Do not use CEDRI to submit 

information you claim as CBI. Anything 

submitted using CEDRI cannot later be 

claimed CBI. Although we do not expect 

persons to assert a claim of CBI, if you 

wish to assert a CBI claim for some of 

the information submitted under 

paragraphs (f)(1)(i) or (ii) of this section, 

you must submit a complete file, 

including information claimed to be 

CBI, to the EPA. The file must be 

generated using the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT website. Submit the file on a 

compact disc, flash drive, or other 

commonly used electronic storage 

medium and clearly mark the medium 

as CBI. Mail the electronic medium to 

U.S. EPA/OAQPS/CORE CBI Office, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same file with the CBI 

omitted must be submitted to the EPA 

via the EPA’s CDX as described in 

paragraphs (f)(1)(i) and (ii). All CBI 

claims must be asserted at the time of 

submission. Furthermore, under CAA 

section 114(c), emissions data is not 

entitled to confidential treatment, and 

the EPA is required to make emissions 

data available to the public. Thus, 

emissions data will not be protected as 

CBI and will be made publicly available. 

(2) If you are the owner or operator of 

an affected engine, you shall submit a 

semi-annual report, at least every six 

months, in PDF format to the EPA via 

CEDRI or analogous electronic reporting 

approach provided by the EPA to report 

data required by this section. The report 

shall contain the following information: 

(i) The name and address of the owner 

and operator; 

(ii) The address of the subject engine; 

(iii) Longitude and latitude 

coordinates of the subject engine; 

(iv) Identification of the subject 

engine; 

(v) Statement of compliance with the 

applicable emission limit under 

§ 52.41(b); 

(vi) Statement of compliance 

regarding the conduct of maintenance 

and operations in a manner consistent 

with good air pollution control practices 

for minimizing emissions; 

(vii) The date and results of the 

performance test conducted pursuant to 

§ 52.41(d); 

(viii) If applicable, a statement 

documenting any change in the 

operating characteristics of the subject 

engine; and 

(ix) A statement certifying that the 

information included in the semiannual report is complete and accurate. 

(3) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of EPA system outage for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of EPA system outage, you must meet 

the requirements outlined in paragraphs 

(f)(3)(i) through (vii) of this section. 

(i) You must have been or will be 

precluded from accessing CEDRI and 

submitting a required report within the 

time prescribed due to an outage of 

either the EPA’s CEDRI or CDX systems. 

(ii) The outage must have occurred 

within the period of time beginning five 

business days prior to the date that the 

submission is due. 

(iii) The outage may be planned or 

unplanned. 

(iv) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(v) You must provide to the 

Administrator a written description 

identifying: 

(A) The date(s) and time(s) when CDX 

or CEDRI was accessed and the system 

was unavailable; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to EPA system outage; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(vi) The decision to accept the claim 

of EPA system outage and allow an 

extension to the reporting deadline is 

solely within the discretion of the 

Administrator. 

(vii) In any circumstance, the report 

must be submitted electronically as 

soon as possible after the outage is 

resolved. 

(4) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of force majeure for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of force majeure, you must meet the 

requirements outlined in paragraphs 

(f)(4)(i) through (v) of this section. 

(i) You may submit a claim if a force 

majeure event is about to occur, occurs, 

or has occurred or there are lingering 

effects from such an event within the 

period of time beginning five business 

days prior to the date the submission is 

due. For the purposes of this section, a 

force majeure event is defined as an 

event that will be or has been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevents you from complying with 

the requirement to submit a report 

electronically within the time period 

prescribed. Examples of such events are 

acts of nature (e.g., hurricanes, 

earthquakes, or floods), acts of war or 

terrorism, or equipment failure or safety 

hazard beyond the control of the 


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affected facility (e.g., large scale power 

outage). 

(ii) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(iii) You must provide to the 

Administrator: 

(A) A written description of the force 

majeure event; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to the force majeure event; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(iv) The decision to accept the claim 

of force majeure and allow an extension 

to the reporting deadline is solely 

within the discretion of the 

Administrator. 

(v) In any circumstance, the reporting 

must occur as soon as possible after the 

force majeure event occurs. 

§ 52.42 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Cement and 

Concrete Product Manufacturing Industry? 

(a) Definitions. All terms not defined 

herein shall have the meaning given 

them in the Act and in subpart A of part 

60. 

Affected unit means a cement kiln 

meeting the applicability criteria of this 

section. 

Cement plant means any facility 

manufacturing cement by either the wet 

or dry process. 

Clinker means the product of a 

cement kiln from which finished 

cement is manufactured by milling and 

grinding. 

Cement kiln means an installation, 

including any associated pre-heater or 

pre-calciner devices, that produces 

clinker by heating limestone and other 

materials to produce Portland cement. 

Operating day means a 24-hour 

period beginning at 12:00 midnight 

during which the kiln produces clinker 

at any time. 

Rolling average means the weighted 

average of all data, meeting QA/QC 

requirements or otherwise normalized, 

collected during the applicable 

averaging period. The period of a rolling 

average stipulates the frequency of data 

averaging and reporting. To demonstrate 

compliance with an operating parameter 

a 30-day rolling average period requires 

calculation of a new average value each 

operating day and shall include the 

average of all the hourly averages of the 

specific operating parameter. For 

demonstration of compliance with an 

emissions limit based on pollutant 

concentration, a 30-day rolling average 

is comprised of the average of all the 

hourly average concentrations over the 

previous 30 operating days. For 

demonstration of compliance with an 

emissions limit based on lbs-pollutant 

per production unit, the 30-day rolling 

average is calculated by summing the 

hourly mass emissions over the 

previous 30 operating days, then 

dividing that sum by the total 

production during the same period. 

(b) Applicability. You are subject to 

the requirements of this section if you 

own or operate a new or existing cement 

kiln that emits or has the potential to 

emit 100 tons per year or more of NOX

and is located within any of the States 

listed in § 52.40(a)(1)(ii), including 

Indian country located within the 

borders of any such State(s). 

(c) Emission limitations (1) If you own 

or operate a cement kiln under 

paragraph (b) of this section you are 

subject to the NOX emissions limits in 

the following table and the NOX source 

cap limit under paragraph (c)(2) of this 

section, beginning with the 2026 ozone 

season and in each ozone season 

thereafter. 

TABLE 1 TO PARAGRAPH (c)(1) 

Kiln type 

Proposed NOX

emissions 

limit 

(lb/ton of 

clinker) 

Long Wet .............................. 4.0 

Long Dry ............................... 3.0 

Preheater .............................. 3.8 

Precalciner ............................ 2.3 

Preheater/Precalciner ........... 2.8 

(2) The NOX source cap limit is 

calculated in accordance with the 

following equation: 

Where: 

CAP2015 Ozone Transport = total allowable 

NOX emissions from all cement kilns 

located at one cement plant, in tons per 

day, on a 30-operating day rolling 

average basis; 

KD = 1.7 pounds NOX per ton of clinker for 

dry preheater-precalciner or precalciner 

kilns; 

KW = 3.4 pounds NOX per ton of clinker for 

long wet kilns; 

ND = the average annual production in tons 

of clinker plus one standard deviation 

for the three most recent calendar years 

from all dry preheater-precalciner or 

precalciner kilns located at one cement 

plant; and 

NW = the average annual production in tons 

of clinker plus one standard deviation 

for the three most recent calendar years 

from all long wet kilns located at one 

cement plant. 

(d)Testing and monitoring 

requirements (1) If you own or operate 

a cement manufacturing plant subject to 

the NOX emissions limits under 

paragraph (c) of this section you must 

conduct performance tests, on a semiannual basis, in accordance with the 

applicable reference test methods of 40 

CFR part 60, Appendix A, any 

alternative test method approved by 

EPA as of April 6, 2022 under 40 CFR 

59.104(f), 60.8(b)(3), 61.13(h)(1)(ii), 

63.7(e)(2)(ii), or 65.158(a)(2) and 

available at EPA’s website (https://

www.epa.gov/emc/broadly-applicableapproved-alternative-test-methods), or 

other methods and procedures approved 

by EPA through notice-and-comment 

rulemaking. You must calculate and 

record the 30-operating day rolling 

emission rate of NOX as the total of all 

hourly emissions data for a cement kiln 

in the preceding 30 days, divided by the 

total tons of clinker produced in that 

kiln during the same 30-operating day 

period using Equation 6 of 40 CFR 

60.64(c)(1), shown in this equation: 


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(KW x NW)+ (KD x ND) 

CAP2015 Ozone Transport = ( pounds 365 days) 

2000 ton x year 
20180 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

Where: 

E30D = 30 kiln operating day average emission 

rate of NOX, in lbs/ton of clinker. 

Ci = Concentration of NOX for hour i, in ppm. 

Qi = Volumetric flow rate of effluent gas for 

hour i, where Ci and Qi are on the same 

basis (either wet or dry), in scf/hr. 

P = 30 days of clinker production during the 

same time period as the NOX emissions 

measured, in tons. 

k = Conversion factor, 1.194 × 10¥7 for NOX, 

in lb/scf/ppm. 

n = Number of kiln operating hours over 30 

kiln operating days. 

(e) Recordkeeping requirements (1) If 

you own or operate a cement 

manufacturing plant subject to the NOX

emissions limits under paragraph (c) of 

this section you must retain records of 

the calculations and measurements as 

required in paragraph (d) of this section 

for the 5-year period specified in 

52.40(b)(3). 

(2) Any records required to be 

maintained by this section that are 

submitted electronically via the EPA’s 

CEDRI may be maintained in electronic 

format. This ability to maintain 

electronic copies does not affect the 

requirement for facilities to make 

records, data, and reports available 

upon request to the EPA as part of an 

on-site compliance evaluation. 

(f) Reporting requirements (1) Within 

60 days after the date of completing 

each performance test required by this 

section, you must submit the results of 

the performance test following the 

procedures specified in paragraphs 

(f)(1)(i) through (iii) of this section: 

(i) Data collected using test methods 

supported by the EPA’s ERT as listed on 

the EPA’s ERT website (https://

www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert) 

at the time of the test. Submit the results 

of the performance test to the EPA via 

the CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section, 

which can be accessed through the 

EPA’s CDX (https://cdx.epa.gov/). The 

data must be submitted in a file format 

generated using the EPA’s ERT. 

Alternatively, you may submit an 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. 

(ii) Data collected using test methods 

that are not supported by the EPA’s ERT 

as listed on the EPA’s ERT website at 

the time of the test. The results of the 

performance test must be included as an 

attachment in the ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. Submit the ERT generated 

package or alternative file to the EPA via 

CEDRI. 

(iii) CBI. Do not use CEDRI to submit 

information you claim as CBI. Anything 

submitted using CEDRI cannot later be 

claimed CBI. Although we do not expect 

persons to assert a claim of CBI, if you 

wish to assert a CBI claim for some of 

the information submitted under 

paragraph (f)(1)(i) or (ii) of this section, 

you must submit a complete file, 

including information claimed to be 

CBI, to the EPA. The file must be 

generated using the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT website. Submit the file on a 

compact disc, flash drive, or other 

commonly used electronic storage 

medium and clearly mark the medium 

as CBI. Mail the electronic medium to 

U.S. EPA/OAQPS/CORE CBI Office, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same file with the CBI 

omitted must be submitted to the EPA 

via the EPA’s CDX as described in 

paragraphs (f)(1)(i) and (ii) of this 

section. All CBI claims must be asserted 

at the time of submission. Furthermore, 

under CAA section 114(c), emissions 

data is not entitled to confidential 

treatment, and the EPA is required to 

make emissions data available to the 

public. Thus, emissions data will not be 

protected as CBI and will be made 

publicly available. 

(2) If you are the owner or operator of 

an affected cement kiln, you shall 

submit a semi-annual, at least every six 

months, report in PDF format to the EPA 

via CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section. 

(3) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of EPA system outage for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of EPA system outage, you must meet 

the requirements outlined in paragraphs 

(f)(3)(i) through (vii) of this section. 

(i) You must have been or will be 

precluded from accessing CEDRI and 

submitting a required report within the 

time prescribed due to an outage of 

either the EPA’s CEDRI or CDX systems. 

(ii) The outage must have occurred 

within the period of time beginning five 

business days prior to the date that the 

submission is due. 

(iii) The outage may be planned or 

unplanned. 

(iv) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(v) You must provide to the 

Administrator a written description 

identifying: 

(A) The date(s) and time(s) when CDX 

or CEDRI was accessed and the system 

was unavailable; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to EPA system outage; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(vi) The decision to accept the claim 

of EPA system outage and allow an 

extension to the reporting deadline is 

solely within the discretion of the 

Administrator. 

(vii) In any circumstance, the report 

must be submitted electronically as 

soon as possible after the outage is 

resolved. 

(4) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of force majeure for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of force majeure, you must meet the 

requirements outlined in paragraphs 

(f)(4)(i) through (v) of this section. 

(i) You may submit a claim if a force 

majeure event is about to occur, occurs, 

or has occurred or there are lingering 

effects from such an event within the 

period of time beginning five business 

days prior to the date the submission is 

due. For the purposes of this section, a 

force majeure event is defined as an 

event that will be or has been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevents you from complying with 

the requirement to submit a report 

electronically within the time period 

prescribed. Examples of such events are 

acts of nature (e.g., hurricanes, 

earthquakes, or floods), acts of war or 

terrorism, or equipment failure or safety 

hazard beyond the control of the 

affected facility (e.g., large scale power 

outage). 


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(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. 

§ 52.43 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Iron and Steel 

Mills and Ferroalloy Manufacturing 

Industry? 

(a) Definitions. All terms not defined 

herein shall have the meaning given 

them in the Act and in subpart A of part 

60. 

Affected unit means any annealing 

furnace, basic oxygen process furnace, 

blast furnace, coke oven facility, electric 

arc furnace, ladle metallurgy furnace, 

ladle/tundish preheating system, reheat 

furnace, taconite production kiln, 

vacuum degasser, and industrial boiler 

meeting the applicability criteria of this 

section, and any such unit contained 

within a BOF Shop meeting the 

applicability criteria of this section. 

Annealing furnace shall mean a 

furnace used to heat materials at very 

high temperatures to change their 

hardness and strength properties. 

Basic Oxygen Process Furnace (BOF) 

shall mean a refractory-lined vessel in 

which high-purity oxygen is blown 

under pressure through a bath of molten 

iron, scrap metal, and fluxes to produce 

steel. This definition includes both top 

and bottom blown furnaces, but does 

not include argon oxygen 

decarburization furnaces. 

Blast furnace means refractory-lined 

furnaces charged through its top with 

iron ore pellets (taconite), sinter, flux 

(limestone and dolomite), and coke in a 

reducing atmosphere to produce iron. 

BOF Shop means the place where 

steel making operations occur, 

beginning with the transfer of molten 

iron (hot metal) from the torpedo car 

and ending just prior to casting the 

molten steel, including hot metal 

transfer, desulfurization, slag skimming, 

refining in a basic oxygen process 

furnace, and ladle metallurgy. 

BOF Baghouse System means the 

control system for control of emissions 

from charging and tapping of the BOFs, 

including the capture hoods, ductwork 

and the BOF Baghouse. 

Coke means carbon product that is 

formed by the thermal distillation of 

coal at high temperatures in the absence 

of air in coke oven batteries. 

Coke Ovens means ovens producing 

coke for use in blast furnaces. 

Day means a calendar day unless 

expressly stated to be a business day. In 

computing any period of time for 

recordkeeping and reporting purposes 

where the last day would fall on a 

Saturday, Sunday, or Federal holiday, 

the period shall run until the close of 

business of the next business day. 

Electric Arc Furnace means a furnace 

equipped with electrodes used to 

produce carbon steels and alloy steels 

primarily by recycling ferrous scrap. 

Exceedance means a reading in excess 

of an applicable opacity or emissions 

limitation. 

Ladle Metallurgy Furnace means a 

furnace used to refine molten steel into 

specialty grades while keeping the steel 

in the ladle. 

Ladle/Tundish Preheaters means 

equipment used to preheat ladles or 

tundishes to minimize temperature drop 

prior to use in iron or molten steel 

refinement. 

Reheat Furnace means a furnace used 

to heat steel product to temperatures at 

which it will be suitable for deformation 

and further processing. 

Steel Production Cycle means the 

operations conducted within the basic 

oxygen process furnace shop that are 

required to produce each batch of steel, 

including scrap charging, preheating, 

hot metal charging, primary oxygen 

blowing, sampling, (vessel turndown 

and turnup), additional oxygen blowing, 

tapping, and deslagging. The steel 

production cycle begins when the scrap 

is charged to the furnace and ends three 

minutes after the slag is emptied from 

the vessel into the slag pot. 

Taconite production kiln means a 

furnace designed to dry and indurate 

taconite concentrates to create taconite 

pellets. 

Vacuum degasser means a unit 

operated within an iron and steel 

facility to expose molten steel at low 

pressure to remove certain gases during 

steel refinement. 

(b) Applicability The requirements of 

this section apply to each new or 

existing emissions unit at an iron and 

steel mill or ferroalloy manufacturing 

facility that directly emits or has the 

potential to emit 100 tons per year or 

more of NOX, and to each BOF Shop 

containing two or more such units that 

collectively emit or have the potential to 

emit 100 tons per year or more of NOX, 

and that is located within any of the 

States listed in § 52.40(a)(1)(ii), 

including Indian country located within 

the borders of any such State(s). 

(c) Emissions Limitations and 

Requirements. Beginning with the 2026 

ozone season and in each ozone season 

thereafter, the emissions limitations in 

the following table must be met on a 3- 

hour rolling average. 

TABLE 1 TO PARAGRAPH (c) 

Emission unit NOX Emissions standard or control requirement 

Blast Furnace ........................................................................................... 0.03 lb/mmBtu. 

Basic Oxygen Process Furnace ............................................................... 0.07 lb/ton steel. 

Electric Arc Furnace ................................................................................. 0.15 lb/ton steel. 

Ladle/tundish Preheaters .......................................................................... 0.06 lb/mmBtu. 

Reheat furnace ......................................................................................... 0.05 lb/mmBtu. 

Annealing Furnace ................................................................................... 0.06 lb/mmBtu. 

Vacuum Degasser .................................................................................... 0.03 lb/mmBtu. 

Ladle Metallurgy Furnace ......................................................................... 0.1 lb/ton steel. 

Taconite Production Kilns ......................................................................... Install and operate low NOX burners as required by 2013 and 2016 

Minnesota FIPs. 40 CFR § 52.1183. 

Coke Ovens (charging) ............................................................................ 0.15 lb/ton of coal charged. 

Coke Oven push cars and pushing-charging machines (pushing) .......... 0.015 lb/ton of coal pushed. 


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352https://archive.epa.gov/reg5oair/taconite/web/ 

html/index.html. 

TABLE 1 TO PARAGRAPH (c)—Continued 

Emission unit NOX Emissions standard or control requirement 

Boilers—Coal, blast furnace gas, and coke oven gas ............................. 0.20 lb/mmBtu. 

Boilers—Residual oil ................................................................................ 0.20 lb/mmBtu. 

Boilers—Distillate oil ................................................................................. 0.12 lb/mmBtu. 

Boilers—Natural gas ................................................................................. 0.08 lb/mmBtu. 

(d) Compliance and Monitoring 

Requirements—(1) Compliance 

Requirements (i) Each affected unit 

identified in Table 1 to paragraph (c) of 

this section must design, install, 

maintain, and continuously operate 

NOX control devices as necessary to 

achieve emissions limits set forth in 

Table 1 to paragraph (c) of this section 

in a manner consistent with good air 

pollution control practices as described 

in 40 CFR 63.6(e). 

(A) If you are the owner or operator 

of an affected unit not identified in 

paragraph (d)(1)(i)(B) of this section, 

you must submit to EPA a work plan for 

each affected unit within 180 days of 

the effective date of this rule identifying 

how each affected unit will comply with 

the emissions limits set forth in Table 1 

to paragraph (c) of this section. Each 

work plan must include identification of 

the control device selected and the 

phased construction timeframe by 

which you will design, install, and 

consistently operate the device. 

(B) For each taconite production kiln 

affected by this rule, you must install, 

maintain, and continuously operate 

low-NOX burners to reduce existing 

average NOX emissions from the facility 

by 40% during all periods of kiln 

operation. 

(1) If you have already installed lowNOX burners as required by the 2013 or 

2016 Minnesota Regional Haze Federal 

Implementation Plans,352 then you must 

submit a report to EPA within 180 days 

of the effective date of this rule 

demonstrating that the low-NOX burner 

is designed to achieve 40% reduction of 

kiln NOX emissions. 

(2) If you have not yet installed lowNOX burners as required by the 2013 or 

2016 Minnesota Regional Haze Federal 

Implementation Plans, then you must 

submit a work plan identifying the lowNOX burner selected and the phased 

construction timeframe by which you 

will design, install, and consistently 

operate the burner. Each work plan shall 

include performance test results 

obtained within five years of the 

effective date of this rule to be used as 

baseline emission testing data providing 

the basis for required emission 

reductions. 

(2) Monitoring Requirements (i) For 

each unit identified in Table 1 to 

paragraph (c) of this section of this rule, 

you must install, operate, and maintain 

a NOX continuous emission monitoring 

system (CEMS) to monitor compliance 

with the emissions limits set forth in 

Table 1 to paragraph (c) of this section. 

Each CEMS shall be installed and 

operated in accordance with 

requirements set forth at 40 CFR part 60, 

appendix B. 

(ii) You must conduct a performance 

evaluation of each CEMS according to 

the requirements in 40 CFR 63.8 and 

according to 40 CFR part 60, appendix 

B. 

(iii) You must notify EPA in writing 

of your intention to conduct a 

performance test at least 60 calendar 

days before the performance test is 

initially scheduled to begin in 

accordance with 40 CFR 63.7 (b). 

(iv) As specified in 40 CFR 

63.8(c)(4)(ii), each CEMS must complete 

a minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. You must have at least 

two data points, each representing a 

different 15-minute period within the 

same hour, to have a valid hour of data. 

(v) All CEMS data must be reduced as 

specified in 40 CFR 63.8(g)(2) and 

recorded as NOX in parts per million by 

volume, dry basis (ppmvd). 

(vi) Proper maintenance. You must 

maintain the CEMS equipment at all 

times that the unit is operating, 

including but not limited to, 

maintaining necessary parts for routine 

repairs of the monitoring equipment. 

(vii) You must conduct all monitoring 

in continuous operation at all times that 

the unit is operating, except for, as 

applicable, monitoring malfunctions, 

associated repairs, and required quality 

assurance or control activities 

(including, as applicable, calibration 

drift checks and required zero and highlevel adjustments). Quality assurance or 

control activities must be performed 

according to procedure 1 of 40 CFR part 

60, appendix F. 

(viii) Data recorded during monitoring 

malfunctions, associated repairs, out-ofcontrol periods, and required quality 

assurance or control activities should 

not be used for purposes of calculating 

data averages. You must use all of the 

data collected from all other periods in 

assessing compliance. A monitoring 

malfunction is any sudden, infrequent, 

not reasonably preventable failure of the 

monitoring equipment to provide valid 

data. Monitoring failures that are caused 

in part by poor maintenance or careless 

operation are not malfunctions. Any 

period for which the monitoring system 

is out-of-control and data are not 

available for required calculations 

constitutes a deviation from the 

monitoring requirements. 

(e) Recordkeeping requirements (1) 

You shall maintain records of the 

following information for each day the 

affected unit operates: 

(i) Calendar date; 

(ii) The average hourly NOX emission 

rates measured or predicted; 

(iii) The 30-day average NOX emission 

rates calculated at the end of each 

affected unit operating day from the 

measured or predicted hourly NOX

emission rates for the preceding 30 

steam generating unit operating days; 

(iv) Identification of the affected unit 

operating days when the calculated 30- 

day average NOX emission rates are in 

excess of the applicable NOX emission 

limit in Table 1 to paragraph (c) of this 

section with the reasons for such excess 

emissions as well as a description of 

corrective actions taken; 

(v) Identification of the affected unit 

operating days for which pollutant data 

have not been obtained, including 

reasons for not obtaining sufficient data 

and a description of corrective actions 

taken; 

(vi) Identification of the times when 

emission data have been excluded from 

the calculation of average emission rates 

and the reasons for excluding data; 

(viii) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS; 

(ix) Description of any modifications 

to the CEMS that could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3 in 

appendix B of 40 CFR part 60; and 

(x) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Procedure 1 of 40 CFR 

part 60, appendix F. 


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(2) Any records required to be 

maintained by this section that are 

submitted electronically via the EPA’s 

CEDRI may be maintained in electronic 

format. This ability to maintain 

electronic copies does not affect the 

requirement for facilities to make 

records, data, and reports available 

upon request to the EPA as part of an 

on-site compliance evaluation. 

(f) Reporting requirements (1) Within 

180 days of the effective date of this 

rule, you shall submit a work plan in 

accordance with requirements set forth 

in paragraph (d)(1)(i)(A) of this section, 

including identification of the control 

device selected and the phased 

construction timeframe by which you 

will design, install, and consistently 

operate the device. For taconite kilns 

subject to paragraph (d)(1)(i)(B)(2) of 

this section each work plan shall 

include performance test results 

obtained within five years of the 

effective date of this rule to be used as 

baseline emission testing data providing 

the basis for required emission 

reductions. 

(2) By no later than March 30, 2026, 

each owner/operator of an affected unit 

shall submit a final report certifying 

installation of each selected control 

device has completed. Each such report 

shall contain dates of final construction 

and relevant performance testing, where 

applicable, demonstrating compliance 

with limits set forth in Table 1 to 

paragraph (c) of this section. 

(3) Within 60 days after the date of 

completing each performance test 

required by this section, you must 

submit the results of the performance 

test or performance evaluation of the 

CEMS following the procedures 

specified in paragraphs (c)(3)(i) through 

(iii) of this section: 

(i) Data collected using test methods 

supported by the EPA’s ERT as listed on 

the EPA’s ERT website (https://

www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert) 

at the time of the test. Submit the results 

of the performance test to the EPA via 

the CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section, 

which can be accessed through the 

EPA’s CDX (https://cdx.epa.gov/). The 

data must be submitted in a file format 

generated using the EPA’s ERT. 

Alternatively, you may submit an 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. 

(ii) Data collected using test methods 

that are not supported by the EPA’s ERT 

as listed on the EPA’s ERT website at 

the time of the test. The results of the 

performance test must be included as an 

attachment in the ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. Submit the ERT generated 

package or alternative file to the EPA via 

CEDRI. 

(iii) CBI. Do not use CEDRI to submit 

information you claim as CBI. Anything 

submitted using CEDRI cannot later be 

claimed CBI. Although we do not expect 

persons to assert a claim of CBI, if you 

wish to assert a CBI claim for some of 

the information submitted under 

paragraph (f)(1)(i) or (ii) of this section, 

you must submit a complete file, 

including information claimed to be 

CBI, to the EPA. The file must be 

generated using the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT website. Submit the file on a 

compact disc, flash drive, or other 

commonly used electronic storage 

medium and clearly mark the medium 

as CBI. Mail the electronic medium to 

U.S. EPA/OAQPS/CORE CBI Office, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same file with the CBI 

omitted must be submitted to the EPA 

via the EPA’s CDX as described in 

paragraphs (f)(1)(i) and (ii). All CBI 

claims must be asserted at the time of 

submission. Furthermore, under CAA 

section 114(c), emissions data is not 

entitled to confidential treatment, and 

the EPA is required to make emissions 

data available to the public. Thus, 

emissions data will not be protected as 

CBI and will be made publicly available. 

(4) You are required to submit excess 

emission reports for any excess 

emissions that occurred during the 

reporting period. Excess emissions are 

defined as any calculated 30-day rolling 

average NOX emission rate, as 

determined under paragraph (c)(3)(iii) of 

this section, that exceeds the applicable 

emission limit in paragraph (c) of this 

section. Excess emission reports must be 

submitted in PDF format to the EPA via 

CEDRI or analogous electronic reporting 

approach provided by the EPA to report 

data required by this section. 

(5) If you own or operate an affected 

unit subject to the continuous 

monitoring requirements for NOX under 

paragraph (d) of this section, you shall 

submit reports containing the 

information recorded under paragraph 

(d) as described in paragraph (e)(6) of 

this section. Compliance reports for 

continuous monitoring must be 

submitted in PDF format to the EPA via 

CEDRI or analogous electronic reporting 

approach provided by the EPA to report 

data required by this section. 

(6) If you own or operate an affected 

unit, you must submit electronic 

quarterly reports no later than 30 days 

after the end of the calendar quarter. 

The reports shall be accompanied by a 

certification from the owner or operator 

indicating whether the affected unit was 

in compliance with the applicable 

emission limits and minimum data 

requirements of this section during the 

reporting period. These quarterly 

reports must be submitted in PDF 

format to the EPA via CEDRI or 

analogous electronic reporting approach 

provided by the EPA to report data 

required by this section. 

(7) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of EPA system outage for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of EPA system outage, you must meet 

the requirements outlined in paragraphs 

(f)(7)(i) through (vii) of this section. 

(i) You must have been or will be 

precluded from accessing CEDRI and 

submitting a required report within the 

time prescribed due to an outage of 

either the EPA’s CEDRI or CDX systems. 

(ii) The outage must have occurred 

within the period of time beginning five 

business days prior to the date that the 

submission is due. 

(iii) The outage may be planned or 

unplanned. 

(iv) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(v) You must provide to the 

Administrator a written description 

identifying: 

(A) The date(s) and time(s) when CDX 

or CEDRI was accessed and the system 

was unavailable; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to EPA system outage; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(vi) The decision to accept the claim 

of EPA system outage and allow an 

extension to the reporting deadline is 

solely within the discretion of the 

Administrator. 

(vii) In any circumstance, the report 

must be submitted electronically as 

soon as possible after the outage is 

resolved. 

(8) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of force majeure for 

failure to timely comply with that 


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reporting requirement. To assert a claim 

of force majeure, you must meet the 

requirements outlined in paragraphs 

(f)(8)(i) through (v) of this section. 

(i) You may submit a claim if a force 

majeure event is about to occur, occurs, 

or has occurred or there are lingering 

effects from such an event within the 

period of time beginning five business 

days prior to the date the submission is 

due. For the purposes of this section, a 

force majeure event is defined as an 

event that will be or has been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevents you from complying with 

the requirement to submit a report 

electronically within the time period 

prescribed. Examples of such events are 

acts of nature (e.g., hurricanes, 

earthquakes, or floods), acts of war or 

terrorism, or equipment failure or safety 

hazard beyond the control of the 

affected facility (e.g., large scale power 

outage). 

(ii) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(iii) You must provide to the 

Administrator: 

(A) A written description of the force 

majeure event; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to the force majeure event; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(iv) The decision to accept the claim 

of force majeure and allow an extension 

to the reporting deadline is solely 

within the discretion of the 

Administrator. 

(v) In any circumstance, the reporting 

must occur as soon as possible after the 

force majeure event occurs. 

§ 52.44 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Glass and Glass 

Product Manufacturing Industry? 

(a) Definitions. All terms not defined 

herein shall have the meaning given 

them in the Act and in subpart A of part 

60. 

Affected units means a glass 

manufacturing furnace meeting the 

applicability criteria of this section. 

All-electric melter means a glass 

melting furnace in which all the heat 

required for melting is provided by 

electric current from electrodes 

submerged in the molten glass, although 

some fossil fuel may be charged to the 

furnace as raw material only. 

Borosilicate recipe means glass 

product composition of the following 

approximate ranges of weight 

proportions: 60 to 80 percent silicon 

dioxide, 4 to 10 percent total R2O (e.g., 

Na2O and K2O), 5 to 35 percent boric 

oxides, and 0 to 13 percent other oxides. 

Container glass means glass made of 

soda-lime recipe, clear or colored, 

which is pressed and/or blown into 

bottles, jars, ampoules, and other 

products listed in Standard Industrial 

Classification 3221 (SIC 3221). 

Experimental furnace means a glass 

melting furnace with the sole purpose of 

operating to evaluate glass melting 

processes, technologies, or glass 

products. An experimental furnace does 

not produce glass that is sold (except for 

further research and development 

purposes) or that is used as a raw 

material for nonexperimental furnaces. 

Flat glass means glass made of sodalime recipe and produced into 

continuous flat sheets and other 

products listed in SIC 3211. 

Glass melting furnace means a unit 

comprising a refractory vessel in which 

raw materials are charged, melted at 

high temperature, refined, and 

conditioned to produce molten glass. 

The unit includes foundations, 

superstructure and retaining walls, raw 

material charger systems, heat 

exchangers, melter cooling system, 

exhaust system, refractory brick work, 

fuel supply and electrical boosting 

equipment, integral control systems and 

instrumentation, and appendages for 

conditioning and distributing molten 

glass to forming apparatuses. The 

forming apparatuses, including the float 

bath used in flat glass manufacturing 

and flow channels in wool fiberglass 

and textile fiberglass manufacturing, are 

not considered part of the glass melting 

furnace. 

Glass produced means the weight of 

the glass pulled from the glass melting 

furnace. 

Hand glass melting furnace means a 

glass melting furnace where the molten 

glass is removed from the furnace by a 

glassworker using a blowpipe or a 

pontil. 

Lead recipe means glass product 

composition of the following ranges of 

weight proportions: 50 to 60 percent 

silicon dioxide, 18 to 35 percent lead 

oxides, 5 to 20 percent total R2O (e.g., 

Na2O and K2O), 0 to 8 percent total R2O3

(e.g., Al2O3), 0 to 15 percent total RO 

(e.g., CaO, MgO), other than lead oxide, 

and 5 to 10 percent other oxides. 

Pressed and blown glass means glass 

which is pressed, blown, or both, 

including textile fiberglass, 

noncontinuous flat glass, noncontainer 

glass, and other products listed in SIC 

3229. It is separated into: Glass of 

borosilicate recipe, Glass of soda-lime 

and lead recipes, and Glass of opal, 

fluoride, and other recipes. 

Raw material means minerals, such as 

silica sand, limestone, and dolomite; 

inorganic chemical compounds, such as 

soda ash (sodium carbonate), salt cake 

(sodium sulfate), and potash (potassium 

carbonate); metal oxides and other 

metal-based compounds, such as lead 

oxide, chromium oxide, and sodium 

antimonate; metal ores, such as 

chromite and pyrolusite; and other 

substances that are intentionally added 

to a glass manufacturing batch and 

melted in a glass melting furnace to 

produce glass. Metals that are naturallyoccurring trace constituents or 

contaminants of other substances are 

not considered to be raw materials. 

Rebricking means cold replacement of 

damaged or worn refractory parts of the 

glass melting furnace. Rebricking 

includes replacement of the refractories 

comprising the bottom, sidewalls, or 

roof of the melting vessel; replacement 

of refractory work in the heat exchanger; 

replacement of refractory portions of the 

glass conditioning and distribution 

system. 

Soda-lime recipe means glass product 

composition of the following ranges of 

weight proportions: 60 to 75 percent 

silicon dioxide, 10 to 17 percent total 

R2O (e.g., Na2O and K2O), 8 to 20 

percent total RO but not to include any 

PbO (e.g., CaO, and MgO), 0 to 8 percent 

total R2O3 (e.g., Al2O3), and 1 to 5 

percent other oxides. 

Textile fiberglass means fibrous glass 

in the form of continuous strands 

having uniform thickness. 

Wool fiberglass means fibrous glass of 

random texture, including fiber glass 

insulation, and other products listed in 

SIC 3296. 

(b) Applicability You are subject to 

the requirements under this section if 

you own or operate a new or existing 

glass manufacturing furnace that 

directly emits or has the potential to 

emit 100 tons per year or more of NOX

and is located within any of the States 

listed in § 52.40(a)(1)(ii), including 

Indian country located within the 

borders of any such State(s). 

(c) Emissions limitations If you own 

or operate an affected unit you are 

subject to the NOX emissions limits in 

the following table beginning with the 

2026 ozone season and in each ozone 

season thereafter: 


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TABLE 1 TO PARAGRAPH (c) 

Furnace type 

Proposed NOX

emissions 

limit 

(lb/ton of glass 

produced) 

Container Glass Manufacturing Furnace ................... 4.0 

Pressed/Blown Glass Manufacturing Furnace or Fiberglass Manufacturing Furnace .................................. 4.0 

Flat Glass Manufacturing 

Furnace ............................. 9.2 

(d) Testing and Monitoring 

Requirements If you own or operate an 

affected unit you must conduct 

performance tests, on a semiannual 

basis, in accordance with the applicable 

reference test methods of 40 CFR part 

60, Appendix A, any alternative test 

method approved by EPA as of April 6, 

2022 under 40 CFR 59.104(f), 60.8(b)(3), 

61.13(h)(1)(ii), 63.7(e)(2)(ii), or 

65.158(a)(2) and available at EPA’s 

website (https://www.epa.gov/emc/ 

broadly-applicable-approvedalternative-test-methods), or other 

methods and procedures approved by 

EPA through notice-and-comment 

rulemaking. Direct measurement or 

material balance using good engineering 

practice shall be used to determine the 

amount of glass pulled during the 

performance test. The rate of glass 

produced is defined as the weight of 

glass pulled from the affected facility 

during the performance test divided by 

the number of hours taken to perform 

the performance test. 

(1) Owners or operators of affected 

units must calculate and record the 30- 

operating day rolling emission rate of 

NOX as the total of all hourly emissions 

data for a glass manufacturing furnace 

in the preceding 30 days, divided by the 

total tons of glass produced in that 

furnace during the same 30-operating 

day period. If a continuous emission 

monitoring system has not been 

installed on the affected unit, the owner 

or operator shall conduct the following 

steps: 

(A) Step 1: determine the average 

pounds of NOX emitted per hour by 

averaging three one-hour tests, 

(B) Step 2: determine the average tons 

of glass removed per hour during the 

same time period as the three one-hour 

tests in step 1, 

(C) Step 3: divide the average pounds 

of NOX emitted per hour determined in 

step 1 by the average tons of glass 

removed per hour determined in step 2, 

(D) Step 4: compare the quotient to 

the emission limits specified at 

§ 52.44(c)(1). 

(2) If a continuous emission 

monitoring system has been installed on 

the affected unit, on a daily basis the 

owner or operator shall conduct the 

following steps: 

(A) Step 1: determine the average 

pounds of NOX emitted per day, 

(B) Step 2: determine the tons of glass 

removed per day, 

(C) Step 3: divide the average pounds 

of NOX emitted per day determined in 

step (1) by the tons of glass removed per 

day determined in step (2). The quotient 

is pounds of NOX emitted per ton of 

glass removed; and 

(D) Step 4: compare the quotient to 

the emission limit specified at 

§ 52.44(c)(1). 

(e) Recordkeeping requirements (1) If 

you own or operate an affected unit, you 

must retain records of the calculations 

and measurements as required in 

paragraph (e) of this section for 5-year 

period specified in 52.40(b)(3). You 

must record the results of each 

inspection and maintenance proposed 

rule in a logbook (written or electronic 

format). You shall keep the logbook 

onsite and make the logbook available to 

the permitting authority upon request, 

consistent with the requirements of 40 

CFR part 63, subpart SSSSSS, 

§ 63.11457(c). 

(2) Any records required to be 

maintained by this section that are 

submitted electronically via the EPA’s 

CEDRI may be maintained in electronic 

format. This ability to maintain 

electronic copies does not affect the 

requirement for facilities to make 

records, data, and reports available 

upon request to the EPA as part of an 

on-site compliance evaluation. 

(f) Reporting requirements (1) Within 

60 days after the date of completing 

each performance test required by this 

section, you must submit the results of 

the performance test following the 

procedures specified in paragraphs 

(e)(1)(i) through (iii) of this section: 

(i) Data collected using test methods 

supported by the EPA’s ERT as listed on 

the EPA’s ERT website (https://

www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert) 

at the time of the test. Submit the results 

of the performance test to the EPA via 

the CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section, 

which can be accessed through the 

EPA’s CDX (https://cdx.epa.gov/). The 

data must be submitted in a file format 

generated using the EPA’s ERT. 

Alternatively, you may submit an 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. 

(ii) Data collected using test methods 

that are not supported by the EPA’s ERT 

as listed on the EPA’s ERT website at 

the time of the test. The results of the 

performance test must be included as an 

attachment in the ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. Submit the ERT generated 

package or alternative file to the EPA via 

CEDRI. 

(iii) CBI. Do not use CEDRI to submit 

information you claim as CBI. Anything 

submitted using CEDRI cannot later be 

claimed CBI. Although we do not expect 

persons to assert a claim of CBI, if you 

wish to assert a CBI claim for some of 

the information submitted under 

paragraph (f)(1)(i) or (ii) of this section, 

you must submit a complete file, 

including information claimed to be 

CBI, to the EPA. The file must be 

generated using the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT website. Submit the file on a 

compact disc, flash drive, or other 

commonly used electronic storage 

medium and clearly mark the medium 

as CBI. Mail the electronic medium to 

U.S. EPA/OAQPS/CORE CBI Office, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same file with the CBI 

omitted must be submitted to the EPA 

via the EPA’s CDX as described in 

paragraphs (f)(1)(i) and (ii). All CBI 

claims must be asserted at the time of 

submission. Furthermore, under CAA 

section 114(c), emissions data is not 

entitled to confidential treatment, and 

the EPA is required to make emissions 

data available to the public. Thus, 

emissions data will not be protected as 

CBI and will be made publicly available. 

(2) If you own or operate an affected 

unit, you shall submit a semi-annual 

report, at least every six months, in PDF 

format to the EPA via CEDRI or 

analogous electronic reporting approach 

provided by the EPA to report data 

required by this section. 

(3) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of EPA system outage for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of EPA system outage, you must meet 

the requirements outlined in paragraphs 

(f)(3)(i) through (vii) of this section. 

(i) You must have been or will be 

precluded from accessing CEDRI and 

submitting a required report within the 

time prescribed due to an outage of 

either the EPA’s CEDRI or CDX systems. 

(ii) The outage must have occurred 

within the period of time beginning five 

business days prior to the date that the 

submission is due. 


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20186 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

(iii) The outage may be planned or 

unplanned. 

(iv) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(v) You must provide to the 

Administrator a written description 

identifying: 

(A) The date(s) and time(s) when CDX 

or CEDRI was accessed and the system 

was unavailable; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to EPA system outage; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(vi) The decision to accept the claim 

of EPA system outage and allow an 

extension to the reporting deadline is 

solely within the discretion of the 

Administrator. 

(vii) In any circumstance, the report 

must be submitted electronically as 

soon as possible after the outage is 

resolved. 

(4) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of force majeure for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of force majeure, you must meet the 

requirements outlined in paragraphs 

(f)(4)(i) through (v) of this section. 

(i) You may submit a claim if a force 

majeure event is about to occur, occurs, 

or has occurred or there are lingering 

effects from such an event within the 

period of time beginning five business 

days prior to the date the submission is 

due. For the purposes of this section, a 

force majeure event is defined as an 

event that will be or has been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevents you from complying with 

the requirement to submit a report 

electronically within the time period 

prescribed. Examples of such events are 

acts of nature (e.g., hurricanes, 

earthquakes, or floods), acts of war or 

terrorism, or equipment failure or safety 

hazard beyond the control of the 

affected facility (e.g., large scale power 

outage). 

(ii) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(iii) You must provide to the 

Administrator: 

(A) A written description of the force 

majeure event; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to the force majeure event; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(iv) The decision to accept the claim 

of force majeure and allow an extension 

to the reporting deadline is solely 

within the discretion of the 

Administrator. 

(v) In any circumstance, the reporting 

must occur as soon as possible after the 

force majeure event occurs. 

§ 52.45 What are the requirements of the 

Federal Implementation Plans (FIPs) 

relating to ozone season emissions of 

nitrogen oxides from the Basic Chemical 

Manufacturing, Petroleum and Coal 

Products Manufacturing, and Pulp, Paper, 

and Paperboard Mills Industries? 

(a) Definitions. All terms not defined 

herein shall have the meaning given 

them in the Act and in subpart A of 40 

CFR part 60. 

Affected unit means an industrial 

boiler meeting the applicability criteria 

of this section. 

(b) Applicability. (1) The requirements 

of this section apply to each new or 

existing boiler with a design capacity of 

100 mmBtu/hr or greater fueled by coal, 

residual oil, distillate oil, or natural gas, 

located at sources that are within the 

Basic Chemical Manufacturing industry 

(NAICS code 3251xx), the Petroleum 

and Coal Products Manufacturing 

industry (NAICS code 3241xx), and the 

Pulp, Paper, and Paperboard industry 

(NAICS code 3221xx), and which is 

located within any of the States listed in 

§ 52.40(a)(1)(ii), including Indian 

country located within the borders of 

any such State(s). 

(c) Emission limitations. Beginning 

with the 2026 ozone season and in each 

ozone season thereafter, the following 

emission limits apply, based on a 30- 

day averaging time: 

(1) Coal-fired industrial boilers: 0.20 

lbs NOX/mmBtu; 

(2) Residual oil-fired industrial 

boilers: 0.15 lbs NOX/mmBtu; 

(3) Distillate oil-fired industrial 

boilers: 0.12 lbs NOX/mmBtu; and 

(4) Natural gas-fired industrial boilers: 

0.08 lbs NOX/mmBtu. 

(d) Initial compliance testing. (1) To 

determine compliance with the 

emission limits for NOX identified in 

paragraph (c) of this section, you shall 

conduct an initial compliance test as 

described in 40 CFR § 60.8 using the 

continuous system for monitoring NOX

specified by EPA Test Method 7E— 

Determination of Nitrogen Oxide 

Emissions from Stationary Sources 

(Instrumental Analyzer Procedure), as 

described at 40 CFR part 60, Appendix 

A–4. In lieu of the timing of the 

compliance test described in 40 CFR 

60.8(a), the test shall be conducted 

within 90 days from the installation of 

the pollution control equipment used to 

comply with the NOX emission limits in 

paragraph (c) of this section. 

(2) For the initial compliance test, 

NOX emissions from the affected unit 

shall be monitored for 30 successive 

operating days and the 30-day average 

emission rate will be used to determine 

compliance with the NOX emission 

limits in paragraph (c) of this section. 

The 30-day average emission rate is 

calculated as the average of all hourly 

emission data recorded by the 

monitoring system during the 30-day 

test period. 

(e) Monitoring requirements. (1) The 

NOX emission limits in paragraph (c) of 

this section shall apply at all times. 

(2) You shall install, calibrate, 

maintain, and operate a continuous 

emissions monitoring system (CEMS) 

for measuring NOX emissions and either 

oxygen (O2) or carbon dioxide (CO2), 

unless the Administrator has approved 

a request from the you to use an 

alternative monitoring technique under 

paragraph (e)(8) of this section. If you 

have previously installed a NOX

emission rate CEMS to meet the 

requirements of 40 CFR part 75 and 

continue to meet the ongoing 

requirements of 40 CFR part 75, that 

CEMS may be used to meet the 

monitoring requirements of this section. 

(3) The CEMS required under 

paragraph (e)(2) of this section shall be 

operated and data recorded during all 

periods of operation of the affected unit 

except for CEMS breakdowns and 

repairs. Data shall be recorded during 

calibration checks and zero and span 

adjustments. 

(4) The 1-hour average NOX emission 

rates measured by the CEMS required by 

paragraph (e)(2) of this section shall be 

expressed in terms of lbs/mmBtu heat 

input and shall be used to calculate the 

average emission rates under 40 CFR 

52.45(c). 

(5) Following the date on which the 

initial compliance test is completed, 

you shall determine compliance with 

the applicable NOX emission limit in 

paragraph (c) of this section on a 

continuous basis using a 30-day rolling 


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average emission rate unless the affected 

unit monitors emissions by means of an 

alternative monitoring procedure 

approved pursuant to paragraph (e)(8) of 

this section. A new 30-day rolling 

average emission rate is calculated for 

each operating day as the average of all 

the hourly NOX emission data for the 

preceding 30 operating days. 

(6) The procedures under 40 CFR 

60.13 shall be followed for installation, 

evaluation, and operation of the 

continuous monitoring systems. 

Additionally, the span value for units 

combusting coal shall be 1,000 ppm 

NOX, and for units combusting oil or gas 

the span value shall be 500 ppm NOX. 

As an alternative to meeting the span 

value requirements stated above, you 

may elect to use the NOX span values 

determined according to section 2.1.2 in 

appendix A to 40 CFR part 75. 

(7) When NOX emission data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks and zero and 

span adjustments, emission data will be 

obtained by using standby monitoring 

systems, Method 7 of 40 CFR part 60, 

Method 7A of 40 CFR part 60, or other 

approved reference methods to provide 

emission data for a minimum of 75 

percent of the operating hours in each 

affected unit operating day, in at least 

22 out of 30 successive operating days. 

(8) Installation of a CEMS for NOX

may be delayed until after the initial 

performance test has been conducted. If 

you demonstrate during the 

performance test that emissions of NOX

are less than 70 percent of the 

applicable emission limit in paragraph 

(c) of this section, a CEMS for measuring 

NOX emissions is not required. If you 

demonstrate its boiler emits less than 70 

percent of the applicable emission limit 

chooses to not install a CEMS, you must 

submit a written request to the 

Administrator that documents the 

results of the initial performance test 

and includes an alternative monitoring 

procedure that will be used to track 

compliance with the applicable NOX

emission limit(s) in paragraph (c) of this 

section. The Administrator will 

consider the request and, following 

public notice and comment, may 

approve the alternative monitoring 

procedure with or without revision, or 

disapprove the request. Upon receipt of 

a disapproved request, you will have 

one year to install a CEMS in 

accordance with the provisions for 

CEMS described in paragraph (e) of this 

section. 

(f) Recordkeeping requirements (1) 

You shall record and maintain records 

of the amounts of each fuel combusted 

during each calendar month. 

(2) You shall maintain records of the 

following information for each day the 

affected unit operates: 

(i) Calendar date; 

(ii) The average hourly NOX emission 

rates (expressed as lbs NO2/mmBtu heat 

input) measured or predicted; 

(iii) The 30-day average NOX emission 

rates calculated at the end of each 

affected unit operating day from the 

measured or predicted hourly NOX

emission rates for the preceding 30 

steam generating unit operating days; 

(iv) Identification of the affected unit 

operating days when the calculated 30- 

day average NOX emission rates are in 

excess of the applicable NOX emission 

limit in paragraph (c) of this section 

with the reasons for such excess 

emissions as well as a description of 

corrective actions taken; 

(v) Identification of the affected unit 

operating days for which pollutant data 

have not been obtained, including 

reasons for not obtaining sufficient data 

and a description of corrective actions 

taken; 

(vi) Identification of the times when 

emission data have been excluded from 

the calculation of average emission rates 

and the reasons for excluding data; 

(vii) Identification of ‘‘F’’ factor used 

for calculations, method of 

determination, and type of fuel 

combusted; 

(viii) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS; 

(ix) Description of any modifications 

to the CEMS that could affect the ability 

of the CEMS to comply with 

Performance Specification 2 or 3 in 

appendix B of 40 CFR part 60; and 

(x) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Procedure 1 of 40 CFR 

part 60, appendix F. 

(3) Any records required to be 

maintained by this section that are 

submitted electronically via the EPA’s 

CEDRI may be maintained in electronic 

format. This ability to maintain 

electronic copies does not affect the 

requirement for facilities to make 

records, data, and reports available 

upon request to the EPA as part of an 

on-site compliance evaluation. 

(g) Reporting requirements. (1) Within 

60 days after the date of completing 

each performance test required by this 

section, you must submit the results of 

the performance test or performance 

evaluation of the CEMS following the 

procedures specified in paragraphs (g)(i) 

through (iii) of this section: 

(i) Data collected using test methods 

supported by the EPA’s ERT as listed on 

the EPA’s ERT website (https://

www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert) 

at the time of the test. Submit the results 

of the performance test to the EPA via 

the CEDRI or analogous electronic 

reporting approach provided by the EPA 

to report data required by this section, 

which can be accessed through the 

EPA’s CDX (https://cdx.epa.gov/). The 

data must be submitted in a file format 

generated using the EPA’s ERT. 

Alternatively, you may submit an 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. 

(ii) Data collected using test methods 

that are not supported by the EPA’s ERT 

as listed on the EPA’s ERT website at 

the time of the test. The results of the 

performance test must be included as an 

attachment in the ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT 

website. Submit the ERT generated 

package or alternative file to the EPA via 

CEDRI. 

(iii) CBI. Do not use CEDRI to submit 

information you claim as CBI. Anything 

submitted using CEDRI cannot later be 

claimed CBI. Although we do not expect 

persons to assert a claim of CBI, if you 

wish to assert a CBI claim for some of 

the information submitted under 

paragraph (g)(1)(i) or (ii) of this section, 

you must submit a complete file, 

including information claimed to be 

CBI, to the EPA. The file must be 

generated using the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT website. Submit the file on a 

compact disc, flash drive, or other 

commonly used electronic storage 

medium and clearly mark the medium 

as CBI. Mail the electronic medium to 

U.S. EPA/OAQPS/CORE CBI Office, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same file with the CBI 

omitted must be submitted to the EPA 

via the EPA’s CDX as described in 

paragraphs (g)(1)(i) and (ii) of this 

section. All CBI claims must be asserted 

at the time of submission. Furthermore, 

under CAA section 114(c), emissions 

data is not entitled to confidential 

treatment, and the EPA is required to 

make emissions data available to the 

public. Thus, emissions data will not be 

protected as CBI and will be made 

publicly available. 

(2) You are required to submit excess 

emission reports for any excess 

emissions that occurred during the 

reporting period. Excess emissions are 

defined as any calculated 30-day rolling 

average NOX emission rate, as 

determined under paragraph (g)(3)(iii) of 

this section, that exceeds the applicable 

emission limit in paragraph (c) of this 

section. Excess emission reports must be 


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submitted in PDF format to the EPA via 

CEDRI or analogous electronic reporting 

approach provided by the EPA to report 

data required by this section. 

(3) If you own or operate an affected 

unit subject to the continuous 

monitoring requirements for NOX under 

paragraph (e) of this section, you shall 

submit reports containing the 

information recorded under paragraph 

(e) of this section as described in 

paragraph (g)(2) of this section. 

Compliance reports for continuous 

monitoring must be submitted in PDF 

format to the EPA via CEDRI or 

analogous electronic reporting approach 

provided by the EPA to report data 

required by this section. 

(4) If you own or operate an affected 

unit, you must submit electronic 

quarterly reports no later than 30 days 

after the end of the calendar quarter. 

The reports shall be accompanied by a 

certification from the owner or operator 

indicating whether the affected unit was 

in compliance with the applicable 

emission limits and minimum data 

requirements of this section during the 

reporting period. These quarterly 

reports must be submitted in PDF 

format to the EPA via CEDRI or 

analogous electronic reporting approach 

provided by the EPA to report data 

required by this section. 

(5) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of EPA system outage for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of EPA system outage, you must meet 

the requirements outlined in paragraphs 

(g)(5)(i) through (vii) of this section. 

(i) You must have been or will be 

precluded from accessing CEDRI and 

submitting a required report within the 

time prescribed due to an outage of 

either the EPA’s CEDRI or CDX systems. 

(ii) The outage must have occurred 

within the period of time beginning five 

business days prior to the date that the 

submission is due. 

(iii) The outage may be planned or 

unplanned. 

(iv) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(v) You must provide to the 

Administrator a written description 

identifying: 

(A) The date(s) and time(s) when CDX 

or CEDRI was accessed and the system 

was unavailable; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to EPA system outage; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(vi) The decision to accept the claim 

of EPA system outage and allow an 

extension to the reporting deadline is 

solely within the discretion of the 

Administrator. 

(vii) In any circumstance, the report 

must be submitted electronically as 

soon as possible after the outage is 

resolved. 

(6) If you are required to 

electronically submit a report through 

CEDRI in the EPA’s CDX, you may 

assert a claim of force majeure for 

failure to timely comply with that 

reporting requirement. To assert a claim 

of force majeure, you must meet the 

requirements outlined in paragraphs 

(g)(6)(i) through (v) of this section. 

(i) You may submit a claim if a force 

majeure event is about to occur, occurs, 

or has occurred or there are lingering 

effects from such an event within the 

period of time beginning five business 

days prior to the date the submission is 

due. For the purposes of this section, a 

force majeure event is defined as an 

event that will be or has been caused by 

circumstances beyond the control of the 

affected facility, its contractors, or any 

entity controlled by the affected facility 

that prevents you from complying with 

the requirement to submit a report 

electronically within the time period 

prescribed. Examples of such events are 

acts of nature (e.g., hurricanes, 

earthquakes, or floods), acts of war or 

terrorism, or equipment failure or safety 

hazard beyond the control of the 

affected facility (e.g., large scale power 

outage). 

(ii) You must submit notification to 

the Administrator in writing as soon as 

possible following the date you first 

knew, or through due diligence should 

have known, that the event may cause 

or has caused a delay in reporting. 

(iii) You must provide to the 

Administrator: 

(A) A written description of the force 

majeure event; 

(B) A rationale for attributing the 

delay in reporting beyond the regulatory 

deadline to the force majeure event; 

(C) A description of measures taken or 

to be taken to minimize the delay in 

reporting; and 

(D) The date by which you propose to 

report, or if you have already met the 

reporting requirement at the time of the 

notification, the date you reported. 

(iv) The decision to accept the claim 

of force majeure and allow an extension 

to the reporting deadline is solely 

within the discretion of the 

Administrator. 

(v) In any circumstance, the reporting 

must occur as soon as possible after the 

force majeure event occurs. 

Subpart B—Alabama 

■ 5. Amend § 52.54 by revising 

paragraphs (b)(2) and (3) and adding 

paragraphs (b)(4) and (5) to read as 

follows: 

§ 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 

§ 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 


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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 

§ 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 § 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 § 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 

§ 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 

■ 6. Amend § 52.184 by: 

■ a. Redesignating paragraphs (a) 

through (c) as paragraphs (a)(1) through 

(3); 

■ b. In newly redesignated paragraph 

(a)(2), removing ‘‘2017 and each 

subsequent year.’’ and adding in its 

place ‘‘2017 through 2022.’’, and 

removing the second sentence; 

■ c. Revising newly redesignated 

paragraph (a)(3); and 

■ d. Adding paragraphs (a)(4) and (5) 

and (b). 

The revision and additions read as 

follows: 

§ 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 

§ 52.38(b)(1) and (b)(2)(iii), except to the 

extent the Administrator’s approval is 

partial or conditional. 

(4) Notwithstanding the provisions of 

paragraph (a)(3) of this section, if, at the 

time of the approval of Arkansas’ SIP 

revision described in paragraph (a)(3) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart GGGGG of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of CSAPR 

NOX Ozone Season Group 3 allowances 

to such units for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

(5) Notwithstanding the provisions of 

paragraph (a)(2) of this section, after 

2022 the provisions of § 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 § 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 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart F—California 

■ 7. Add § 52.284 to read as follows: 

§ 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 § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart I—Delaware 

■ 8. Amend § 52.440 by adding 

paragraph (d) to read as follows: 

§ 52.440 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Delaware and for which requirements 

are set forth under the CSAPR NOX

Ozone Season Group 3 Trading Program 

in subpart GGGGG of part 97 of this 

chapter must comply with such 

requirements with regard to emissions 

occurring in 2023 and each subsequent 

year. The obligation to comply with 

such requirements will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to 

Delaware’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the CSAPR Federal 

Implementation Plan (FIP) under 

§ 52.38(b)(1) and (b)(2)(iii), except to the 

extent the Administrator’s approval is 

partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Delaware’s SIP 


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revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart GGGGG of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of CSAPR 

NOX Ozone Season Group 3 allowances 

to such units for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

Subpart O—Illinois 

■ 9. Amend § 52.731 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart P—Indiana 

■ 10. Amend § 52.789 by: 

■ a. In paragraph (b)(2), removing 

‘‘(b)(2)(iv), except’’ and adding in its 

place ‘‘(b)(2)(ii), except’’; 

■ b. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ c. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart S—Kentucky 

■ 11. Amend § 52.940 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart T—Louisiana 

■ 12. Amend § 52.984 by: 

■ a. In paragraph (d)(3), revising the 

second and third sentences; 

■ b. Revising paragraph (d)(4); 

■ c. In paragraph (d)(5), adding ‘‘and 

Indian country within the borders of the 

State’’ after ‘‘in the State’’; and 

■ d. Adding paragraph (e). 

The revision and addition read as 

follows: 

§ 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 

§ 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 § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart V—Maryland 

■ 13. Amend § 52.1084 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 52.1084 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) The owner and operator of each 

source located in the State of Maryland 

and for which requirements are set forth 

in § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart X—Michigan 

■ 14. Amend § 52.1186 by: 

■ a. In paragraph (e)(3), revising the 

second and third sentences; 

■ b. Revising paragraph (e)(4); 

■ c. In paragraph (e)(5), adding ‘‘and 

Indian country within the borders of the 

State’’ after ‘‘in the State’’; and 

■ d. Adding paragraph (f). 

The revision and addition read as 

follows: 

§ 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 


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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 

§ 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 § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart Y—Minnesota 

■ 15. Amend § 52.1240 by adding 

paragraphs (d) and (e) to read as follows: 

§ 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 

§ 52.38(b)(1) and (b)(2)(iii) for those 

sources and units, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Minnesota’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Minnesota’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of subpart 

GGGGG of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of CSAPR NOX Ozone Season Group 3 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

(e) The owner and operator of each 

source located in the State of Minnesota 

and Indian country within the borders 

of the State and for which requirements 

are set forth in § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart Z—Mississippi 

■ 16. Amend § 52.1284 by: 

■ a. Redesignating paragraphs (a) 

through (c) as paragraphs (a)(1) through 

(3); 

■ b. In newly redesignated paragraph 

(a)(2), removing ‘‘2017 and each 

subsequent year.’’ and adding in its 

place ‘‘2017 through 2022.’’, and 

removing the second and third 

sentences; 

■ c. Revising newly redesignated 

paragraph (a)(3); and 

■ d. Adding paragraphs (a)(4) and (5) 

and (b). 

The revision and additions read as 

follows: 

§ 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 

§ 52.38(b)(1) and (b)(2)(iii) for those 

sources and units, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Mississippi’s SIP. 

(4) Notwithstanding the provisions of 

paragraph (a)(3) of this section, if, at the 

time of the approval of Mississippi’s SIP 

revision described in paragraph (a)(3) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of subpart 

GGGGG of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of CSAPR NOX Ozone Season Group 3 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

(5) Notwithstanding the provisions of 

paragraph (a)(2) of this section, after 

2022 the provisions of § 97.826(c) of this 

chapter (concerning the transfer of 


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CSAPR NOX Ozone Season Group 2 

allowances between certain accounts 

under common control), the provisions 

of § 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 

§ 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 § 52.40 and 

§ 52.41, § 52.42, § 52.43, § 52.44, or 

§ 52.45 must comply with such 

requirements with regard to emissions 

occurring in 2026 and each subsequent 

year. 

Subpart AA—Missouri 

■ 17. Amend § 52.1326 by revising 

paragraph (b)(2) and (3) and adding 

paragraphs (b)(4) and (5) and (c) to read 

as follows: 

§ 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 

§ 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 

§ 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 § 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 § 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 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart DD—Nevada 

■ 18. Add § 52.1492 to read as follows: 

§ 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 

§ 52.38(b)(1) and (b)(2)(iii) for those 

sources and units, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Nevada’s 

SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Nevada’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of subpart 

GGGGG of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of CSAPR NOX Ozone Season Group 3 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

(b) The owner and operator of each 

source located in the State of Nevada 

and Indian country within the borders 

of the State and for which requirements 

are set forth in § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 


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Subpart FF—New Jersey 

■ 19. Amend § 52.1584 by: 

■ a. In paragraph (e)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (f). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart HH—New York 

■ 20. Amend § 52.1684 by: 

■ a. In paragraph (b)(3), revising the 

second and third sentences; 

■ b. Revising paragraph (b)(4); 

■ c. In paragraph (b)(5), adding ‘‘and 

Indian country within the borders of the 

State’’ after ‘‘in the State’’; and 

■ d. Adding paragraph (c). 

The revision and addition read as 

follows: 

§ 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 

§ 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 § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart KK—Ohio 

■ 21. Amend § 52.1882 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 

§ 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart LL—Oklahoma 

■ 22. Amend § 52.1930 by: 

■ a. Redesignating paragraphs (a) 

through (c) as paragraphs (a)(1) through 

(3); 

■ b. In newly redesignated paragraph 

(a)(2), removing ‘‘2017 and each 

subsequent year.’’ and adding in its 

place ‘‘2017 through 2022.’’, and 

removing the second and third 

sentences; 

■ c. Revising newly redesignated 

paragraph (a)(3); and 

■ c. Adding paragraphs (a)(4) and (5) 

and (b). 

The revision and additions read as 

follows: 

§ 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 

§ 52.38(b)(1) and (b)(2)(iii) for those 

sources and units, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Oklahoma’s SIP. 

(4) Notwithstanding the provisions of 

paragraph (a)(3) of this section, if, at the 

time of the approval of Oklahoma’s SIP 

revision described in paragraph (a)(3) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of subpart 

GGGGG of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of CSAPR NOX Ozone Season Group 3 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

(5) Notwithstanding the provisions of 

paragraph (a)(2) of this section, after 

2022 the provisions of § 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 § 97.826(e) of this chapter 

(concerning the conversion of amounts 


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20194 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

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 

§ 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 § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart NN—Pennsylvania 

■ 23. Amend § 52.2040 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and 

§ 52.41, § 52.42, § 52.43, § 52.44, or 

§ 52.45 must comply with such 

requirements with regard to emissions 

occurring in 2026 and each subsequent 

year. 

Subpart RR—Tennessee 

■ 24. Amend § 52.2240 by: 

■ a. In paragraph (e)(2), removing ‘‘2017 

and each subsequent year.’’ and adding 

in its place ‘‘2017 through 2022.’’, and 

removing the second sentence; 

■ b. Revising paragraph (e)(3); and 

■ c. Adding paragraphs (e)(4) and (5). 

The revision and additions read as 

follows: 

§ 52.2240 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(e) * * * 

(3) The owner and operator of each 

source and each unit located in the State 

of Tennessee and for which 

requirements are set forth under the 

CSAPR NOX Ozone Season Group 3 

Trading Program in subpart GGGGG of 

part 97 of this chapter must comply 

with such requirements with regard to 

emissions occurring in 2023 and each 

subsequent year. The obligation to 

comply with such requirements will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Tennessee’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the CSAPR Federal Implementation 

Plan (FIP) under § 52.38(b)(1) and 

(b)(2)(iii), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(4) Notwithstanding the provisions of 

paragraph (e)(3) of this section, if, at the 

time of the approval of Tennessee’s SIP 

revision described in paragraph (e)(3) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart GGGGG of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of CSAPR 

NOX Ozone Season Group 3 allowances 

to such units for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

(5) Notwithstanding the provisions of 

paragraph (e)(2) of this section, after 

2022 the provisions of § 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 § 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 

§ 97.811(e) of this chapter (concerning 

the recall of CSAPR NOX Ozone Season 

Group 2 allowances equivalent in 

quantity and usability to all such 

allowances allocated to units in the 

State for control periods after 2022) 

shall continue to apply. 

Subpart SS—Texas 

■ 25. Amend § 52.2283 by: 

■ a. In paragraph (d)(2), removing ‘‘2017 

and each subsequent year.’’ and adding 

in its place ‘‘2017 through 2022.’’, and 

removing the second and third 

sentences; 

■ b. Revising paragraph (d)(3); and 

■ c. Adding paragraphs (d)(4) and (5) 

and (e). 

The revision and additions read as 

follows: 

§ 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 

§ 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 § 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 § 97.826(e) of this chapter 


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(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 

§ 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 § 52.40 and § 52.41, § 52.42, 

§ 52.43, § 52.44, or § 52.45 must comply 

with such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart TT—Utah 

■ 26. Add § 52.2356 to read as follows: 

§ 52.2356 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Utah and Indian country within the 

borders of the State and for which 

requirements are set forth under the 

CSAPR NOX Ozone Season Group 3 

Trading Program in subpart GGGGG of 

part 97 of this chapter must comply 

with such requirements with regard to 

emissions occurring in 2023 and each 

subsequent year. The obligation to 

comply with such requirements with 

regard to sources and units in the State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Utah’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the CSAPR Federal 

Implementation Plan (FIP) under 

§ 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 § 52.40 and § 52.41, § 52.42, 

§ 52.43, § 52.44, or § 52.45 must comply 

with such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart VV—Virginia 

■ 27. Amend § 52.2440 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, § 52.43, 

§ 52.44, or § 52.45 must comply with 

such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart XX—West Virginia 

■ 28. Amend § 52.2540 by: 

■ a. In paragraph (b)(3), removing 

‘‘(b)(2)(v), except’’ and adding in its 

place ‘‘(b)(2)(iii), except’’; and 

■ b. Adding paragraph (c). 

The addition reads as follows: 

§ 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 § 52.40 and § 52.41, § 52.42, 

§ 52.43, § 52.44, or § 52.45 must comply 

with such requirements with regard to 

emissions occurring in 2026 and each 

subsequent year. 

Subpart YY—Wisconsin 

■ 29. Amend § 52.2587 by: 

■ a. In paragraph (e)(2), removing ‘‘2017 

and each subsequent year.’’ and adding 

in its place ‘‘2017 through 2022.’’, and 

removing the second and third 

sentences; 

■ b. Revising paragraph (e)(3); and 

■ c. Adding paragraphs (e)(4) and (5) 

and (f). 

The revision and additions read as 

follows: 

§ 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 

§ 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 


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20196 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

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 § 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 § 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 

§ 97.811(e) of this chapter (concerning 

the recall of CSAPR NOX Ozone Season 

Group 2 allowances equivalent in 

quantity and usability to all such 

allowances allocated to units in the 

State and Indian country within the 

borders of the State for control periods 

after 2022) shall continue to apply. 

(f) The owner and operator of each 

source located in the State of Wisconsin 

and Indian country within the borders 

of the State and for which requirements 

are set forth in § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

Subpart ZZ—Wyoming 

■ 30. Add § 52.2638 to read as follows: 

§ 52.2638 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Wyoming and Indian country within 

the borders of the State and for which 

requirements are set forth under the 

CSAPR NOX Ozone Season Group 3 

Trading Program in subpart GGGGG of 

part 97 of this chapter must comply 

with such requirements with regard to 

emissions occurring in 2023 and each 

subsequent year. The obligation to 

comply with such requirements with 

regard to sources and units in the State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Wyoming 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the CSAPR Federal 

Implementation Plan (FIP) under 

§ 52.38(b)(1) and (b)(2)(iii) for those 

sources and units, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in areas of 

Indian country within the borders of the 

State not subject to the State’s SIP 

authority will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Wyoming’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Wyoming’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of CSAPR NOX Ozone Season Group 3 

allowances under subpart GGGGG of 

part 97 of this chapter to units in the 

State and areas of Indian country within 

the borders of the State subject to the 

State’s SIP authority for a control period 

in any year, the provisions of subpart 

GGGGG of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of CSAPR NOX Ozone Season Group 3 

allowances to such units for each such 

control period shall continue to apply, 

unless provided otherwise by such 

approval of the State’s SIP revision. 

(b) The owner and operator of each 

source located in the State of Wyoming 

and Indian country within the borders 

of the State and for which requirements 

are set forth in § 52.40 and § 52.41, 

§ 52.42, § 52.43, § 52.44, or § 52.45 must 

comply with such requirements with 

regard to emissions occurring in 2026 

and each subsequent year. 

PART 75—CONTINUOUS EMISSION 

MONITORING 

■ 31. The authority citation for part 75 

is revised to read as follows: 

Authority: 42 U.S.C. 7401–7671q and 

7651k note. 

■ 32. Amend § 75.72 by: 

■ a. In paragraph (c)(3), removing 

‘‘appendix B of this part.’’ and adding 

in its place ‘‘appendix B to this part.’’; 

■ b. In paragraph (e)(1)(ii), removing 

‘‘heat input from’’ and adding in its 

place ‘‘heat input rate to’’; 

■ c. In paragraph (e)(2), removing 

‘‘appendix D of this part’’ and adding in 

its place ‘‘appendix D to this part’’; and 

■ d. Adding paragraph (f). 

The addition reads as follows: 

§ 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 

§ 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. 

* * * * * 

■ 33. Amend § 75.73 by: 

■ a. Revising paragraph (a)(3); 

■ b. In paragraph (c)(1), removing ‘‘NoX

emissions’’ and adding in its place 

‘‘NOX emissions’’; 

■ c. Adding a paragraph heading to 

paragraph (c)(2); 

■ d. Revising paragraphs (c)(3) and (f)(1) 

introductory text; 

■ e. Removing and reserving paragraph 

(f)(1)(i)(B); 

■ f. In paragraph (f)(1)(ii)(G), removing 

‘‘appendix D;’’ and adding in its place 

‘‘appendix D to this part;’’; 

■ g. Adding paragraphs (f)(1)(ix) and (x); 

■ h. Adding a paragraph heading to 

paragraph (f)(2); and 

■ i. Revising paragraph (f)(4). 

The revisions and addition reads as 

follows: 

§ 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 § 75.53(g)(1) in electronic 

format and the information in 

§ 75.53(g)(2) in hardcopy format. In 

addition, to the extent applicable, each 

monitoring plan shall contain the 

information in § 75.53(h)(1)(i) and 

(h)(2)(i) in electronic format and the 

information in § 75.53(h)(1)(ii) and 

(h)(2)(ii) in hardcopy format. For units 

using the low mass emissions excepted 

methodology under § 75.19, the 

monitoring plan shall include the 

additional information in § 75.53(h)(4)(i) 

and (h)(4)(ii). The monitoring plan also 


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shall include a seasonal controls 

indicator and an ozone season fuelswitching 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 longterm cold storage (as defined in § 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 

§ 52.38(b)(12) of this chapter and 

determining NOX mass emission rate at 

a common stack, apportioned hourly 

NOX mass emission rate for the unit, lb/ 

hr. 

(x) On and after January 1, 2024, for 

a unit subject to a backstop daily NOX

emission rate under subpart GGGGG of 

part 97 of this chapter or under a state 

implementation plan approved under 

§ 52.38(b)(12) of this chapter: 

(A) Daily NOX emissions (lbs) for each 

day of the reporting period; 

(B) Daily heat input (mmBtu) for each 

day of the reporting period; 

(C) Daily average NOX emission rate 

(lb/mmBtu, rounded to the nearest 

thousandth) for each day of the 

reporting period; 

(D) Daily NOX emissions (lbs) 

exceeding the applicable backstop daily 

NOX emission rate for each day of the 

reporting period; and 

(E) Cumulative NOX emissions (tons, 

rounded to the nearest tenth) exceeding 

the applicable backstop daily NOX

emission rate during the ozone season. 

(2) Verification of identification codes 

and formulas. * * * 

* * * * * 

(4) Electronic format, method of 

submission, and explanatory 

information. The designated 

representative shall comply with all of 

the quarterly reporting requirements in 

§ 75.64(d), (f), and (g). 

■ 34. Revise § 75.75 to read as follows: 

§ 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. 

■ 35. Amend appendix F to part 75 by: 

■ a. Adding section 5.3.3; 

■ b. In section 8.1.2, revising the 

introductory text preceding Equation F– 

25; 

■ 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); 

■ d. In section 8.5.2, removing ‘‘the 

hourly NOX mass emissions at each 

unit’’ and adding in its place ‘‘hourly 

NOX mass emissions at the common 

stack.’’; and 

■ e. Adding section 8.5.3. 

The additions and revisions read as 

follows 

Appendix F to Part 75—Conversion 

Procedures 

* * * * * 

5.3.3 Calculate total daily heat input for 

a unit using a flow monitor and diluent 

monitor to calculate heat input, using the 

following equation: 

Where: 

HId = Total heat input for a unit for the day, 

mmBtu. 

HIh = Heat input rate for the unit for hour ‘‘h’’ 

from Equation F–15, F–16, F–17, F–18, 

F–21a, or F–21b, mmBtu/hr. 

th = Unit operating time, fraction of the hour 

(0.00 to 1.00, in equal increments from 

one hundredth to one quarter of an hour, 

at the option of the owner or operator). 

h = Designation of a particular hour. 

* * * * * 

8.1.2 If NOX emission rate is 

measured at a common stack and heat 

input rate is measured at the unit level, 

calculate the hourly heat input rate at 

the common stack according to the 

following formula: 

* * * * * 

8.4 Use the following equations to 

calculate daily, quarterly, cumulative 

ozone season, and cumulative year-todate NOX mass emissions: 

(a) When hourly NOX mass emissions 

are reported in lb., use Eq. F–27 to 

calculate quarterly, cumulative ozone 

season, and cumulative year-to-date 

NOX mass emissions in tons. * * * 

(b) When hourly NOX mass emission 

rate is reported in lb/hr, use Eq. F–27a 

to calculate quarterly, cumulative ozone 

season, and cumulative year-to-date 

NOX mass emissions in tons. * * * 

(c) To calculate daily NOX mass 

emissions for a unit in pounds, use Eq. 

F–27b. 


lotter on DSK11XQN23PROD with PROPOSALS2EP06AP22.006</GPH>

(Eq. F-18c) 

24 

Hid= L Hlhth 

h=l 
20198 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

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: 

Where: 

E(NOX)i = Apportioned NOX mass emission 

rate for unit ‘‘i’’, lb/hr. 

E(NOX)CS = NOX mass emission rate at the 

common stack, lb/hr. 

HIi = Heat input rate for unit ‘‘i’’, mmBtu/hr. 

ti = Operating time for unit ‘‘i’’, fraction of 

the hour (0.00 to 1.00, in equal 

increments from one hundredth to one 

quarter of an hour, at the option of the 

owner or operator). 

tCS = Common stack operating time, fraction 

of the hour (0.00 to 1.00, in equal 

increments from one hundredth to one 

quarter of an hour, at the option of the 

owner or operator). 

n = Number of units using the common stack. 

i = Designation of a particular unit. 

PART 78—APPEAL PROCEDURES 

■ 36. The authority citation for part 78 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

■ 37. Amend § 78.1 by: 

■ a. In paragraph (b)(17)(viii), adding 

‘‘or (e)’’ after ‘‘§ 97.826(d)’’; 

■ b. In paragraph (b)(17)(ix), adding ‘‘or 

(e)’’ after ‘‘§ 97.811(d)’’; and 

■ c. Revising paragraph (b)(19). 

The revision reads as follows: 

§ 78.1 Purpose and scope. 

* * * * * 

(b) * * * 

(19) Under subpart GGGGG of part 97 

of this chapter, 

(i) The decision on the calculation of 

a state CSAPR NOX Ozone Season 

Group 3 trading budget under 

§ 97.1010(a)(3) of this chapter. 

(ii) The decision on the allocation of 

CSAPR NOX Ozone Season Group 3 

allowances under § 97.1011 or § 97.1012 

of this chapter. 

(iii) The decision on the transfer of 

CSAPR NOX Ozone Season Group 3 

allowances under § 97.1023 of this 

chapter. 

(iv) The decision on the deduction of 

CSAPR NOX Ozone Season Group 3 

allowances under § 97.1024, § 97.1025, 

or § 97.1026(d) of this chapter. 

(v) The correction of an error in an 

Allowance Management System account 

under § 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 § 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 § 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 

■ 38. The authority citation for part 97 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7426, 7491, 7601, and 7651, et seq. 

Subpart AAAAA—CSAPR NOX Annual 

Trading Program 

§ 97.402 [Amended] 

■ 39. Amend § 97.402 by: 

■ 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’’; 

■ 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 

■ 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’’; 

§ 97.411 [Amended] 

■ 40. Amend § 97.411 by: 

■ 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 

■ 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’’. 

§ 97.412 [Amended] 

■ 41. Amend § 97.412 by: 

■ 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’’; 

■ 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’’; 

■ c. In paragraph (a)(10), removing 

‘‘State, is allocated’’ and adding in its 

place ‘‘State and areas of Indian country 


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(Eq. F-27b) 

(Eq. F-28) 

24 

M(NOX)d = I E(NOX)h th 

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Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 20199 

within the borders of the State subject 

to the State’s SIP authority, is 

allocated’’; 

■ 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 

■ 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’’. 

§ 97.421 [Amended] 

■ 42. In § 97.421, amend paragraph (f)(2) 

by removing ‘‘2022’’ and adding in its 

place ‘‘2024’’, and removing ‘‘third’’ 

before ‘‘year after the year’’. 

§ 97.426 [Amended] 

■ 43. In § 97.426, amend paragraph (c) 

by removing ‘‘State (or Indian’’ and 

adding in its place ‘‘State (and Indian’’. 

Subpart BBBBB—CSAPR NOX Ozone 

Season Group 1 Trading Program 

§ 97.502 [Amended] 

■ 44. Amend § 97.502 by: 

■ 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’’; 

■ 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’’; 

■ c. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 allowance’’, 

adding ‘‘or (e)’’ after ‘‘§ 97.826(d)’’, and 

adding ‘‘or less’’ after ‘‘one ton’’; 

■ 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 

■ e. In the definition of ‘‘State’’, 

removing ‘‘(b)(2)(i) and (ii), and’’ and 

adding in its place ‘‘(b)(2)(i), and’’. 

§ 97.511 [Amended] 

■ 45. Amend § 97.511 by: 

■ 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 

■ 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’’. 

§ 97.512 [Amended] 

■ 46. Amend § 97.512 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

■ 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 

■ 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’’. 

§ 97.521 [Amended] 

■ 47. In § 97.521, amend paragraph (f)(2) 

by removing ‘‘2022’’ and adding in its 

place ‘‘2024’’, and removing ‘‘third’’ 

before ‘‘year after the year’’. 

■ 48. Amend § 97.526 by: 

■ a. In paragraph (c), removing ‘‘State 

(or Indian’’ and adding in its place 

‘‘State (and Indian’’; 

■ b. In paragraph (d)(1) introductory 

text, removing ‘‘§ 52.38(b)(2)(i) of this 

chapter (or’’ and adding in its place 

‘‘§ 52.38(b)(2)(i)(A) of this chapter 

(and’’; 

■ c. In paragraph (d)(1)(ii), removing 

‘‘except a State listed in § 52.38(b)(2)(i)’’ 

and adding in its place ‘‘listed in 

§ 52.38(b)(2)(ii)’’; 

■ d. In paragraph (d)(1)(iv), removing 

‘‘§ 52.38(b)(2)(iii) or (iv) of this chapter 

(or’’ and adding in its place 

‘‘§ 52.38(b)(2)(ii) of this chapter (and’’; 

■ e. Revising paragraph (d)(2)(i); 

■ f. In paragraph (d)(2)(ii), removing 

‘‘§ 52.38(b)(2)(v) of this chapter (or’’ and 

adding in its place ‘‘§ 52.38(b)(2)(iii)(A) 

of this chapter (and’’; 

■ g. Adding paragraph (d)(2)(iii); 

■ h. In paragraph (e)(1), removing 

‘‘chapter (or Indian’’ and adding in its 

place ‘‘chapter (and Indian’’; 

■ i. In paragraph (e)(2), removing 

‘‘§ 52.38(b)(2)(iv) of this chapter (or’’ 

and adding in its place 

‘‘§ 52.38(b)(2)(iii)(A) of this chapter 

(and’’; and 

■ j. Adding paragraph (e)(3). 

The revisions and additions read as 

follows: 

§ 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 § 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 

§ 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 § 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 § 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 

§ 97.826(e)(1), the owner or operator of 

a CSAPR NOX Ozone Season Group 1 


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source in a State listed in 

§ 52.38(b)(2)(iii)(B) of this chapter (and 

Indian country within the borders of 

such a State) may satisfy a requirement 

to hold a given number of CSAPR NOX

Ozone Season Group 1 allowances for 

the control period in 2015 or 2016 by 

holding instead, in a general account 

established for this sole purpose, an 

amount of CSAPR NOX Ozone Season 

Group 3 allowances for the control 

period in 2023 (or any later control 

period for which the allowance transfer 

deadline defined in § 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 

§ 97.826(e)(1)(ii). 

Subpart CCCCC—CSAPR SO2 Group 1 

Trading Program 

§ 97.602 [Amended] 

■ 49. Amend § 97.602 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

§ 97.611 [Amended] 

■ 50. Amend § 97.611 by: 

■ 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 

■ 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’’. 

§ 97.612 [Amended] 

■ 51. Amend § 97.612 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

■ 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 

■ 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’’. 

§ 97.621 [Amended] 

■ 52. In § 97.621, amend paragraph (f)(2) 

by removing ‘‘2022’’ and adding in its 

place ‘‘2024’’, and removing ‘‘third’’ 

before ‘‘year after the year’’. 

§ 97.626 [Amended] 

■ 53. In § 97.626, amend paragraph (c) 

by removing ‘‘State (or Indian’’ and 

adding in its place ‘‘State (and Indian’’. 

Subpart DDDDD—CSAPR SO2 Group 2 

Trading Program 

■ 54. Amend § 97.702 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

■ d. Adding in alphabetical order a 

definition for ‘‘CSAPR NOX Ozone 

Season Group 3 Trading Program’’; and 

■ 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’’. 

§ 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 § 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 § 52.38(b)(10) 

or (11) of this chapter or that is 

established in a SIP revision approved 

by the Administrator under 

§ 52.38(b)(12) of this chapter), as a 

means of mitigating interstate transport 

of ozone and NOX. 

* * * * * 

§ 97.711 [Amended] 

■ 55. Amend § 97.711 by: 

■ 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 

■ 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’’. 

§ 97.712 [Amended] 

■ 56. Amend § 97.712 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

■ 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 

■ 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’’. 


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§ 97.721 [Amended] 

■ 57. In § 97.721, amend paragraph (f)(2) 

by removing ‘‘2022’’ and adding in its 

place ‘‘2024’’, and removing ‘‘third’’ 

before ‘‘year after the year’’. 

§ 97.726 [Amended] 

■ 58. In § 97.726, amend paragraph (c) 

by removing ‘‘State (or Indian’’ and 

adding in its place ‘‘State (and Indian’’. 

§ 97.734 [Amended] 

■ 59. In § 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 

■ 60. Amend § 97.802 by: 

■ a. In the definition of ‘‘assurance 

account’’, removing ‘‘base CSAPR’’ and 

adding in its place ‘‘CSAPR’’; 

■ b. Removing the definitions for ‘‘base 

CSAPR NOX Ozone Season Group 2 

source’’ and ‘‘base CSAPR NOX Ozone 

Season Group 2 unit’’; 

■ c. In the definition of ‘‘common 

designated representative’’, removing 

‘‘base CSAPR’’ and adding in its place 

‘‘CSAPR’’; 

■ d. In the definition of ‘‘common 

designated representative’s assurance 

level’’, revising paragraph (1); 

■ e. In the definition of ‘‘common 

designated representative’s share’’, 

removing ‘‘base CSAPR’’ and adding in 

its place ‘‘CSAPR’’ each time it appears; 

■ 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’’; 

■ g. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 allowance’’, 

adding ‘‘or (e)’’ after ‘‘§ 97.826(d)’’, and 

adding ‘‘or less’’ after ‘‘one ton’’; 

■ 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 

■ 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: 

§ 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 § 52.38(b)(8) or 

(9) of this chapter, multiplied by the 

sum of the State NOX Ozone Season 

Group 2 trading budget under 

§ 97.810(a) and the State’s variability 

limit under § 97.810(b) for such control 

period, and divided by such State NOX

Ozone Season Group 2 trading budget; 

* * * * * 

§ 97.806 [Amended] 

■ 61. In § 97.806, amend paragraphs 

(c)(2)(i) introductory text, (c)(2)(i)(B), 

(c)(2)(iii) and (iv), and (c)(3)(ii) by 

removing ‘‘base CSAPR’’ and adding in 

its place ‘‘CSAPR’’ each time it appears. 

§ 97.810 [Amended] 

■ 62. In § 97.810, amend paragraphs 

(a)(1)(i) through (iii), (a)(2)(i) and (ii), 

(a)(12)(i) through (iii), (a)(13)(i) and (ii), 

(a)(17)(i) through (iii), (a)(19)(i) and (ii), 

(a)(20)(i) through (iii), (a)(23)(i) through 

(iii), and (b)(1), (2), (12), (13), (17), (19), 

(20), and (23) by removing ‘‘and 

thereafter’’ and adding in its place 

‘‘through 2022’’. 

■ 63. Amend § 97.811 by: 

■ 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’’; 

■ 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’’; 

■ c. In paragraph (d)(1), removing 

‘‘§ 52.38(b)(2)(iv) of this chapter (or’’ 

and adding in its place 

‘‘§ 52.38(b)(2)(ii)(B) of this chapter 

(and’’; and 

■ d. Adding paragraph (e). 

The addition reads as follows: 

§ 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 

§ 52.38(b) of this chapter, the provisions 

of this paragraph and paragraphs (e)(2) 

through (7) of this section shall apply 

with regard to each CSAPR NOX Ozone 

Season Group 2 allowance that was 

allocated for a control period after 2022 

to any unit (including a permanently 

retired unit qualifying for an exemption 

under § 97.805) in a State listed in 

§ 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 § 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 


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requirement under paragraph (e)(2)(i) of 

this section corresponding to such 

CSAPR NOX Ozone Season Group 2 

allowance shall apply to the most recent 

former owners and operators of the 

source before the occurrence of such a 

transaction. 

(C) The Administrator will not 

adjudicate any private legal dispute 

among the owners and operators of a 

source or among the former owners and 

operators of a source, including any 

disputes relating to the requirements to 

surrender CSAPR NOX Ozone Season 

Group 2 allowances for the source under 

paragraph (e)(2)(i) of this section. 

(3)(i) As soon as practicable on or 

after [EFFECTIVE DATE OF FINAL 

RULE], the Administrator will send a 

notification to the designated 

representative for each source described 

in paragraph (e)(1) of this section 

identifying the amounts of CSAPR NOX

Ozone Season Group 2 allowances 

allocated for each control period after 

2022 and recorded in the source’s 

compliance account and the 

corresponding surrender requirements 

for the source under paragraph (e)(2)(i) 

of this section. 

(ii) As soon as practicable on or after 

[15 DAYS AFTER EFFECTIVE DATE OF 

FINAL RULE], the Administrator will 

deduct from the compliance account for 

each source described in paragraph 

(e)(1) of this section CSAPR NOX Ozone 

Season Group 2 allowances eligible to 

satisfy the surrender requirements for 

the source under paragraph (e)(2)(i) of 

this section until all such surrender 

requirements for the source are satisfied 

or until no more CSAPR NOX Ozone 

Season Group 2 allowances eligible to 

satisfy such surrender requirements 

remain in such compliance account. 

(iii) As soon as practicable after 

completion of the deductions under 

paragraph (e)(3)(ii) of this section, the 

Administrator will identify for each 

source described in paragraph (e)(1) of 

this section the amounts, if any, of 

CSAPR NOX Ozone Season Group 2 

allowances allocated for each control 

period after 2022 and recorded in the 

source’s compliance account for which 

the corresponding surrender 

requirements under paragraph (e)(2)(i) 

of this section have not been satisfied 

and will send a notification concerning 

such identified amounts to the 

designated representative for the source. 

(iv) With regard to each source for 

which unsatisfied surrender 

requirements under paragraph (e)(2)(i) 

of this section remain after the 

deductions under paragraph (e)(3)(ii) of 

this section: 

(A) Except as provided in paragraph 

(e)(3)(iv)(B) of this section, not later 

than September 15, 2023, the owners 

and operators of the source shall hold 

sufficient CSAPR NOX Ozone Season 

Group 2 allowances eligible to satisfy 

such unsatisfied surrender requirements 

under paragraph (e)(2)(i) of this section 

in the source’s compliance account. 

(B) With regard to any portion of such 

unsatisfied surrender requirements that 

apply to former owners and operators of 

the source pursuant to paragraph 

(e)(2)(ii)(B) of this section, not later than 

September 15, 2023, such former 

owners and operators shall hold 

sufficient CSAPR NOX Ozone Season 

Group 2 allowances eligible to satisfy 

such portion of the unsatisfied 

surrender requirements under paragraph 

(e)(2)(i) of this section either in the 

source’s compliance account or in 

another Allowance Management System 

account identified to the Administrator 

on or before such date in a submission 

by the authorized account 

representative for such account. 

(C) As soon as practicable on or after 

September 15, 2023, the Administrator 

will deduct from the Allowance 

Management System account identified 

in accordance with paragraph 

(e)(3)(iv)(A) or (B) of this section CSAPR 

NOX Ozone Season Group 2 allowances 

eligible to satisfy the surrender 

requirements for the source under 

paragraph (e)(2)(i) of this section until 

all such surrender requirements for the 

source are satisfied or until no more 

CSAPR NOX Ozone Season Group 2 

allowances eligible to satisfy such 

surrender requirements remain in such 

account. 

(v) When making deductions under 

paragraph (e)(3)(ii) or (iv) of this section 

to address the surrender requirements 

under paragraph (e)(2)(i) of this section 

for a given source: 

(A) The Administrator will make 

deductions to address any surrender 

requirements with regard to first the 

2023 control period and then the 2024 

control period. 

(B) When making deductions to 

address the surrender requirements with 

regard to a given control period, the 

Administrator will first deduct CSAPR 

NOX Ozone Season Group 2 allowances 

allocated for such given control period 

and will then deduct CSAPR NOX

Ozone Season Group 2 allowances 

allocated for each successively earlier 

control period in sequence. 

(C) When deducting CSAPR NOX

Ozone Season Group 2 allowances 

allocated for a given control period from 

a given Allowance Management System 

account, the Administrator will first 

deduct CSAPR NOX Ozone Season 

Group 2 allowances initially recorded in 

the account under § 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 § 97.526(d) or § 97.823 in 

the order of recordation. 

(4)(i) To the extent the surrender 

requirements under paragraph (e)(2)(i) 

of this section corresponding to any 

CSAPR NOX Ozone Season Group 2 

allowances allocated for a control 

period after 2022 and initially recorded 

in a given source’s compliance account 

have not been fully satisfied through the 

deductions under paragraph (e)(3) of 

this section, as soon as practicable on or 

after November 15, 2023, the 

Administrator will deduct such initially 

recorded CSAPR NOX Ozone Season 

Group 2 allowances from any 

Allowance Management System 

accounts in which such CSAPR NOX

Ozone Season Group 2 allowances are 

held, making such deductions in any 

order determined by the Administrator, 

until all such surrender requirements 

for such source have been satisfied or 

until all such CSAPR NOX Ozone 

Season Group 2 allowances have been 

deducted, except as provided in 

paragraph (e)(4)(ii) of this section. 

(ii) If no person with an ownership 

interest in a given CSAPR NOX Ozone 

Season Group 2 allowance as of April 

30, 2022, was an owner or operator of 

the source in whose compliance account 

such CSAPR NOX Ozone Season Group 

2 allowance was initially recorded, was 

a direct or indirect parent or subsidiary 

of an owner or operator of such source, 

or was directly or indirectly under 

common ownership with an owner or 

operator of such source, the 

Administrator will not deduct such 

CSAPR NOX Ozone Season Group 2 

allowance under paragraph (e)(4)(i) of 

this section. For purposes of this 

paragraph, each owner or operator of a 

source shall be deemed to be a person 

with an ownership interest in any 

CSAPR NOX Ozone Season Group 2 

allowance held in that source’s 

compliance account. The limitation 

established by this paragraph on the 

deductibility of certain CSAPR NOX

Ozone Season Group 2 allowances 

under paragraph (e)(4)(i) of this section 

shall not be construed as a waiver of the 

surrender requirements under paragraph 

(e)(2)(i) of this section corresponding to 

such CSAPR NOX Ozone Season Group 

2 allowances. 

(iii) Not less than 45 days before the 

planned date for any deductions under 

paragraph (e)(4)(i) of this section, the 

Administrator will send a notification to 

the authorized account representative 

for the Allowance Management System 

account from which such deductions 


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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 

CSAPR@epa.gov. Each such 

communication from a designated 

representative must contain the 

certification statement set forth in 

§ 97.814(a), and each such 

communication from the authorized 

account representative for a general 

account must contain the certification 

statement set forth in § 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. 

§ 97.812 [Amended] 

■ 64. Amend § 97.812 by: 

■ 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’’; 

■ 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’’; 

■ 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’’; 

■ 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 

■ 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’’. 

§ 97.821 [Amended] 

■ 65. In § 97.821, amend paragraph (f) 

by removing ‘‘2022’’ and adding in its 

place ‘‘2024’’, and removing ‘‘third’’ 

before ‘‘year after the year’’. 

§ 97.825 [Amended] 

■ 66. In § 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. 

■ 67. Amend § 97.826 by: 

■ a. In paragraph (b), removing ‘‘(c) or 

(d)’’ and adding in its place ‘‘(c), (d), or 

(e)’’; 

■ b. In paragraph (c), removing ‘‘State 

(or Indian’’ and adding in its place 

‘‘State (and Indian’’; 

■ c. In paragraphs (d)(1)(i)(A) and (B), 

removing ‘‘§ 52.38(b)(2)(iv)’’ and adding 

in its place ‘‘§ 52.38(b)(2)(ii)(B)’’; 

■ d. Revising paragraph (d)(1)(i)(C); 

■ e. In paragraph (d)(1)(ii) introductory 

text, removing ‘‘§ 52.38(b)(2)(v)’’ and 

adding in its place ‘‘§ 52.38(b)(2)(iii)’’; 

■ f. Removing and reserving paragraph 

(d)(1)(iii); 

■ g. Revising paragraph (d)(1)(iv) 

introductory text; 

■ h. In paragraphs (d)(1)(iv)(A) and (B), 

removing ‘‘or (d)(1)(iii)(C)’’; 

■ i. In paragraphs (d)(2)(i) and (d)(3), 

removing ‘‘§ 52.38(b)(2)(v) of this 

chapter (or’’ and adding in its place 

‘‘§ 52.38(b)(2)(iii) of this chapter (and’’; 

■ j. Redesignating paragraph (e) as 

paragraph (f) and adding a new 

paragraph (e); 

■ k. Revising newly redesignated 

paragraphs (f)(1) and (2); and 

■ l. Adding paragraph (f)(3). 

The revisions and additions read as 

follows: 

§ 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 § 52.38(b)(2)(iii)(A) of 

this chapter of the variability limits 

under § 97.1010(e) for such States for 

the control period in 2022. 

* * * * * 

(iv) For the compliance account of 

each source to which an amount of 

CSAPR NOX Ozone Season Group 3 

allowances greater than zero is allocated 

under paragraph (d)(1)(ii)(C) of this 

section: 

* * * * * 

(e) Notwithstanding any other 

provision of this subpart, part 52 of this 

chapter, or any SIP revision approved 

under § 52.38(b)(8) or (9) of this chapter: 

(1) By [45 DAYS AFTER EFFECTIVE 

DATE OF FINAL RULE], the 

Administrator will temporarily suspend 

acceptance of CSAPR NOX Ozone 

Season Group 2 allowance transfers 

submitted under § 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 § 52.38(b)(2)(ii)(A) of this 

chapter (and Indian country within the 

borders of such a State): 

(i) The Administrator will deduct all 

CSAPR NOX Ozone Season Group 2 

allowances allocated for the control 

periods in 2017 through 2022 from each 

such account. 

(ii) The Administrator will determine 

a conversion factor equal to the greater 

of 1.0000 or the quotient, expressed to 

four decimal places, of the sum of all 

CSAPR NOX Ozone Season Group 2 

allowances deducted from all such 

accounts under paragraph (e)(1)(i) of 

this section divided by the sum of the 

variability limits for the control period 

in 2024 under § 97.1010(e) for all States 

listed in § 52.38(b)(2)(iii)(B) of this 

chapter. 

(iii) The Administrator will allocate 

and record in each such account an 


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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 § 52.38(b)(2)(iii) of 

this chapter (and Indian country within 

the borders of such a State), the 

Administrator will not record CSAPR 

NOX Ozone Season Group 3 allowances 

in that compliance account but instead 

will allocate and record the amount of 

CSAPR NOX Ozone Season Group 3 

allowances for the control period in 

2023 computed for such source in 

accordance with paragraph (e)(1)(iii) of 

this section in a general account 

identified by the designated 

representative for such source, provided 

that if the designated representative fails 

to identify such a general account in a 

submission to the Administrator by [45 

DAYS AFTER EFFECTIVE DATE OF 

FINAL RULE], the Administrator may 

record such CSAPR NOX Ozone Season 

Group 3 allowances in a general account 

identified or established by the 

Administrator with the designated 

representative as the authorized account 

representative and with the owners and 

operators of such source (as indicated 

on the certificate of representation for 

the source) as the persons represented 

by the authorized account 

representative. 

(v)(A) In computing any amounts of 

CSAPR NOX Ozone Season Group 3 

allowances to be allocated to and 

recorded in general accounts under 

paragraph (e)(1)(iii) of this section, the 

Administrator may group multiple 

general accounts whose ownership 

interests are held by the same or related 

persons or entities and treat the group 

of accounts as a single account for 

purposes of such computation. 

(B) Following a computation for a 

group of general accounts in accordance 

with paragraph (e)(1)(v)(A) of this 

section, the Administrator will allocate 

to and record in each individual 

account in such group a proportional 

share of the quantity of CSAPR NOX

Ozone Season Group 3 allowances 

computed for such group, basing such 

shares on the respective quantities of 

CSAPR NOX Ozone Season Group 2 

allowances removed from such 

individual accounts under paragraph 

(e)(1)(i) of this section. 

(C) In determining the proportional 

shares under paragraph (e)(1)(v)(B) of 

this section, the Administrator may 

employ any reasonable adjustment 

methodology to truncate or round each 

such share up or down to a whole 

number and to cause the total of such 

whole numbers to equal the amount of 

CSAPR NOX Ozone Season Group 3 

allowances computed for such group of 

accounts in accordance with paragraph 

(e)(1)(v)(A) of this section, even where 

such adjustments cause the numbers of 

CSAPR NOX Ozone Season Group 3 

allowances allocated to some individual 

accounts to equal zero. 

(2) After the Administrator has carried 

out the procedures set forth in 

paragraph (e)(1) of this section, upon 

any determination that would otherwise 

result in the initial recordation of a 

given number of CSAPR NOX Ozone 

Season Group 2 allowances in the 

compliance account for a source in a 

State listed in § 52.38(b)(2)(iii)(B) of this 

chapter (and Indian country within the 

borders of such a State), the 

Administrator will not record such 

CSAPR NOX Ozone Season Group 2 

allowances but instead will allocate and 

record in such account an amount of 

CSAPR NOX Ozone Season Group 3 

allowances for the control period in 

2023 computed as the quotient, rounded 

up to the nearest allowance, of such 

given number of CSAPR NOX Ozone 

Season Group 2 allowances divided by 

the conversion factor determined under 

paragraph (e)(1)(ii) of this section. 

(f) * * * 

(1) Except as provided in paragraph 

(f)(3) of this section, after the 

Administrator has carried out the 

procedures set forth in paragraph (d)(1) 

of this section, the owner or operator of 

a CSAPR NOX Ozone Season Group 2 

source in a State listed in 

§ 52.38(b)(2)(iii)(A) of this chapter (and 

Indian country within the borders of 

such a State) may satisfy a requirement 

to hold a given number of CSAPR NOX

Ozone Season Group 2 allowances for 

the control period in a year from 2017 

through 2020 by holding instead, in a 

general account established for this sole 

purpose, an amount of CSAPR NOX

Ozone Season Group 3 allowances for 

the control period in 2021 (or any later 

control period for which the allowance 

transfer deadline defined in § 97.1002 

has passed) computed as the quotient, 

rounded up to the nearest allowance, of 

such given number of CSAPR NOX

Ozone Season Group 2 allowances 

divided by the conversion factor 

determined under paragraph (d)(1)(i)(D) 

of this section. 

(2) Except as provided in paragraph 

(f)(3) of this section, after the 

Administrator has carried out the 

procedures set forth in paragraph (e)(1) 

of this section, the owner or operator of 

a CSAPR NOX Ozone Season Group 2 

source in a State listed in 

§ 52.38(b)(2)(iii)(B) of this chapter (and 

Indian country within the borders of 

such a State) may satisfy a requirement 

to hold a given number of CSAPR NOX

Ozone Season Group 2 allowances for 

the control period in a year from 2017 

through 2022 by holding instead, in a 

general account established for this sole 

purpose, an amount of CSAPR NOX

Ozone Season Group 3 allowances for 

the control period in 2023 (or any later 

control period for which the allowance 

transfer deadline defined in § 97.1002 

has passed) computed as the quotient, 

rounded up to the nearest allowance, of 

such given number of CSAPR NOX

Ozone Season Group 2 allowances 

divided by the conversion factor 

determined under paragraph (e)(1)(ii) of 

this section. 

(3) CSAPR NOX Ozone Season Group 

3 allowances may not be used to satisfy 

requirements to surrender CSAPR NOX

Ozone Season Group 2 allowances 

under § 97.811(d) or (e). 

Subpart FFFFF—Texas SO2 Trading 

Program 

■ 68. Amend § 97.902 by: 

■ 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’’; 

■ 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’’; 

■ c. Adding in alphabetical order a 

definition for ‘‘CSAPR NOX Ozone 

Season Group 3 Trading Program’’; and 

■ 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: 

§ 97.902 Definitions. 

* * * * * 

CSAPR NOX Ozone Season Group 3 

Trading Program means a multi-state 


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NOX air pollution control and emission 

reduction program established in 

accordance with subpart GGGGG of this 

part and § 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 § 52.38(b)(10) 

or (11) of this chapter or that is 

established in a SIP revision approved 

by the Administrator under 

§ 52.38(b)(12) of this chapter), as a 

means of mitigating interstate transport 

of ozone and NOX.

* * * * * 

§ 97.921 [Amended] 

■ 69. In § 97.921, amend paragraph 

(b)(2) by removing ‘‘2022’’ and adding 

in its place ‘‘2024’’, and removing 

‘‘third’’ before ‘‘year after the year’’. 

§ 97.934 [Amended] 

■ 70. In § 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 

■ 71. Amend § 97.1002 by: 

■ a. Revising the definition of ‘‘allocate 

or allocation’’; 

■ b. In the definition of ‘‘allowance 

transfer deadline’’, adding ‘‘primary’’ 

before ‘‘emissions limitation’’; 

■ 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’’; 

■ d. Adding in alphabetical order a 

definition for ‘‘backstop daily NOX

emissions rate’’; 

■ e. In the definition of ‘‘common 

designated representative’s assurance 

level’’, in paragraph (1), removing 

‘‘§ 97.1010(b)’’ and adding in its place 

‘‘§ 97.1010(e)’’, and revising paragraph 

(2); 

■ f. In the definition of ‘‘compliance 

account’’, adding ‘‘primary’’ before 

‘‘emissions limitation’’; 

■ g. Adding in alphabetical order a 

definition for ‘‘CSAPR NOX Ozone 

Season Group 1 Trading Program’’; 

■ h. In the definition of ‘‘CSAPR NOX

Ozone Season Group 2 Trading 

Program’’, removing ‘‘(b)(2)(iii) and (iv), 

and’’ and adding in its place ‘‘(b)(2)(ii), 

and’’; 

■ i. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 allowance’’, 

adding ‘‘or (e)’’ after ‘‘§ 97.826(d)’’, and 

adding ‘‘or less’’ after ‘‘one ton’’; 

■ j. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 allowance 

deduction or deduct CSAPR NOX Ozone 

Season Group 3 allowances’’, adding 

‘‘primary’’ before ‘‘emissions 

limitation’’; 

■ k. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 emissions 

limitation’’, adding ‘‘primary’’ before 

‘‘emissions limitation’’; 

■ l. Adding in alphabetical order a 

definition for ‘‘CSAPR NOX Ozone 

Season Group 3 secondary emissions 

limitation’’; 

■ m. In the definition of ‘‘CSAPR NOX

Ozone Season Group 3 Trading 

Program’’, removing ‘‘(b)(2)(v), and’’ and 

adding in its place ‘‘(b)(2)(iii), and’’; 

■ n. Adding in alphabetical order a 

definition for ‘‘CSAPR SO2 Group 2 

Trading Program’’; 

■ o. In the definition of ‘‘designated 

representative’’, removing ‘‘or CSAPR 

SO2 Group 1 Trading Program, then’’ 

and adding in its place ‘‘CSAPR SO2

Group 1 Trading Program, or CSAPR 

SO2 Group 2 Trading Program, then’’. 

■ p. In the definition of ‘‘excess 

emissions’’, adding ‘‘primary’’ before 

‘‘emissions limitation’’; and 

■ q. In the definition of ‘‘State’’, 

removing ‘‘(b)(2)(v), and’’ and adding in 

its place ‘‘(b)(2)(iii), and’’. 

The revisions and additions read as 

follows: 

§ 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, §§ 97.526(d) and 97.826(d) 

and (e), and any SIP revision submitted 

by the State and approved by the 

Administrator under § 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 setaside; 

(4) An Indian country existing unit 

set-aside; or 

(5) An entity not listed in paragraphs 

(1) through (4) of this definition; 

(6) Provided that, if the 

Administrator, State, or permitting 

authority initially credits, to a CSAPR 

NOX Ozone Season Group 3 unit 

qualifying for an initial credit, a credit 

in the amount of zero CSAPR NOX

Ozone Season Group 3 allowances, the 

CSAPR NOX Ozone Season Group 3 unit 

will be treated as being allocated an 

amount (i.e., zero) of CSAPR NOX

Ozone Season Group 3 allowances. 

* * * * * 

Backstop daily NOX emissions rate 

means an emissions rate limit used in 

the determination of the CSAPR NOX

Ozone Season Group 3 primary 

emissions limitation for a CSAPR NOX

Ozone Season Group 3 source in 

accordance with § 97.1024(b). 

* * * * * 

Common designated representative’s 

assurance level * * * 

(2) Provided that the allocations of 

CSAPR NOX Ozone Season Group 3 

allowances for any control period taken 

into account for purposes of this 

definition shall exclude any CSAPR 

NOX Ozone Season Group 3 allowances 

allocated for such control period under 

§ 97.526(d) or § 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 § 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 

§ 52.38(b)(3) or (4) of this chapter or that 

is established in a SIP revision approved 

by the Administrator under § 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 § 97.1025(c)(1) for a 

control period in a given year, the 

tonnage of NOX emissions calculated for 

the unit in accordance with 

§ 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 § 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 § 52.39(g) or (h) 

of this chapter or that is established in 

a SIP revision approved by the 

Administrator under § 52.39(i) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and SO2.

* * * * * 

■ 72. Amend § 97.1006 by: 


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■ a. Revising paragraph (b)(2), the 

paragraph (c)(1) heading, paragraph 

(c)(1)(i), and paragraph (c)(1)(ii) 

introductory text; 

■ b. Adding paragraphs (c)(1)(iii) and 

(iv); and 

■ c. Revising paragraphs (c)(2)(iii) and 

(c)(3). 

The revisions and additions read as 

follows: 

§ 97.1006 Standard requirements. 

* * * * * 

(b) * * * 

(2) The emissions and heat input data 

determined in accordance with 

§§ 97.1030 through 97.1035 shall be 

used to calculate allocations of CSAPR 

NOX Ozone Season Group 3 allowances 

under §§ 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 §§ 97.1030 through 

97.1035 and rounded to the nearest ton, 

with any fraction of a ton less than 0.50 

being deemed to be zero. 

(c) * * * 

(1) CSAPR NOX Ozone Season Group 

3 primary and secondary emissions 

limitations—(i) Primary emissions 

limitation. As of the allowance transfer 

deadline for a control period in a given 

year, the owners and operators of each 

CSAPR NOX Ozone Season Group 3 

source and each CSAPR NOX Ozone 

Season Group 3 unit at the source shall 

hold, in the source’s compliance 

account, CSAPR NOX Ozone Season 

Group 3 allowances available for 

deduction for such control period under 

§ 97.1024(a) in an amount not less than 

the amount determined under 

§ 97.1024(b), comprising the sum of: 

(A) The tons of total NOX emissions 

for such control period from all CSAPR 

NOX Ozone Season Group 3 units at the 

source; plus 

(B) Two times the sum, for all CSAPR 

NOX Ozone Season Group 3 units at the 

source and all days of the control 

period, of any NOX emissions from such 

a unit on any day of the control period 

exceeding the NOX emissions that 

would have occurred on that day if the 

unit had combusted the same daily heat 

input and emitted at any backstop daily 

NOX emissions rate applicable to the 

unit for that control period. 

(ii) Exceedances of primary emissions 

limitation. If total NOX emissions during 

a control period in a given year from the 

CSAPR NOX Ozone Season Group 3 

units at a CSAPR NOX Ozone Season 

Group 3 source are in excess of the 

CSAPR NOX Ozone Season Group 3 

primary emissions limitation set forth in 

paragraph (c)(1)(i) of this section, then: 

* * * * * 

(iii) Secondary emissions limitation. 

The owner or operator of a base CSAPR 

NOX Ozone Season Group 3 unit subject 

to an emissions limitation under 

§ 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 

§ 97.1025(c)(2). 

(iv) Exceedances of secondary 

emissions limitation. If total NOX

emissions during a control period in a 

given year from a base CSAPR NOX

Ozone Season Group 3 unit are in 

excess of the amount of a CSAPR NOX

Ozone Season Group 3 secondary 

emissions limitation applicable to the 

unit for the control period under 

paragraph (c)(1)(iii) of this section, then 

the owners and operators of the unit and 

the source at which the unit is located 

shall pay any fine, penalty, or 

assessment or comply with any other 

remedy imposed, for the same 

violations, under the Clean Air Act, and 

each ton of such excess emissions and 

each day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(2) * * * 

(iii) Total NOX emissions from all 

base CSAPR NOX Ozone Season Group 

3 units at base CSAPR NOX Ozone 

Season Group 3 sources in a State (and 

Indian country within the borders of 

such State) during a control period in a 

given year exceed the State assurance 

level if such total NOX emissions exceed 

the sum, for such control period, of the 

State NOX Ozone Season Group 3 

trading budget under § 97.1010(a) and 

the State’s variability limit under 

§ 97.1010(e). 

* * * * * 

(3) Compliance periods.(i) A CSAPR 

NOX Ozone Season Group 3 unit shall 

be subject to the requirements under 

paragraphs (c)(1)(i) and (ii) of this 

section, and a base CSAPR NOX Ozone 

Season Group 3 unit shall be subject to 

the requirements under paragraph (c)(2) 

of this section, for the control period 

starting on the later of the applicable 

date in paragraph (c)(3)(i)(A), (B), or (C) 

of this section or the deadline for 

meeting the unit’s monitor certification 

requirements under § 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 

§ 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 

§ 52.38(b)(2)(iii)(B) of this chapter; or 

(C) [EFFECTIVE DATE OF FINAL 

RULE], for a unit in a State (and Indian 

country within the borders of such 

State) listed in § 52.38(b)(2)(iii)(C) of 

this chapter. 

(ii) A base CSAPR NOX Ozone Season 

Group 3 unit shall be subject to the 

requirements under paragraphs 

(c)(1)(iii) and (iv) of this section for the 

control period starting on the later of 

May 1, 2024 or the deadline for meeting 

the unit’s monitor certification 

requirements under § 97.1030(b) and for 

each control period thereafter. 

* * * * * 

■ 73. Revise § 97.1010 to read as 

follows: 

§ 97.1010 State NOX Ozone Season Group 

3 trading budgets, set-asides, and 

variability limits. 

(a) State NOX Ozone Season Group 3 

trading budgets. (1)(i) The State NOX

Ozone Season Group 3 trading budgets 

for allocations of CSAPR NOX Ozone 

Season Group 3 allowances for the 

control periods in 2021, 2022, 2023, and 

2024 are as indicated in Table 1 to this 

paragraph, subject to prorating for the 

control period in 2023 as provided in 

paragraph (a)(1)(ii) of this section: 


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TABLE 1 TO PARAGRAPH (a)(1)(i)—STATE NOX OZONE SEASON GROUP 3 TRADING BUDGETS BY CONTROL PERIOD

[Tons] 

State 2021 2022 

Portion of 

2023 control 

period before 

[EFFECTIVE 

DATE OF 

FINAL RULE], 

before 

prorating 

Portion of 

2023 control 

period on and 

after 

[EFFECTIVE 

DATE OF 

FINAL RULE], 

before 

prorating 

2024 

Alabama ............................................................................... ........................ ........................ 13,211 6,364 6,306 

Arkansas .............................................................................. ........................ ........................ 9,210 8,889 8,889 

Delaware .............................................................................. ........................ ........................ ........................ 384 434 

Illinois ................................................................................... 11,223 9,102 8,179 7,364 7,463 

Indiana ................................................................................. 17,004 12,582 12,553 11,151 9,391 

Kentucky .............................................................................. 17,542 14,051 14,051 11,640 11,640 

Louisiana .............................................................................. 16,291 14,818 14,818 9,312 9,312 

Maryland .............................................................................. 2,397 1,266 1,266 1,187 1,187 

Michigan ............................................................................... 14,384 12,290 9,975 10,718 10,718 

Minnesota ............................................................................. ........................ ........................ ........................ 3,921 3,921 

Mississippi ............................................................................ ........................ ........................ 6,315 5,024 4,400 

Missouri ................................................................................ ........................ ........................ 15,780 11,857 11,857 

Nevada ................................................................................. ........................ ........................ ........................ 2,280 2,372 

New Jersey .......................................................................... 1,565 1,253 1,253 799 799 

New York ............................................................................. 4,079 3,416 3,421 3,763 3,763 

Ohio ...................................................................................... 13,481 9,773 9,773 8,369 8,369 

Oklahoma ............................................................................. ........................ ........................ 11,641 10,265 9,573 

Pennsylvania ........................................................................ 12,071 8,373 8,373 8,855 8,855 

Tennessee ........................................................................... ........................ ........................ 7,736 4,234 4,234 

Texas ................................................................................... ........................ ........................ 52,301 38,284 38,284 

Utah ...................................................................................... ........................ ........................ ........................ 14,981 15,146 

Virginia ................................................................................. 6,331 3,897 3,980 3,090 2,814 

West Virginia ........................................................................ 15,062 12,884 12,884 12,478 12,478 

Wisconsin ............................................................................. ........................ ........................ 7,915 5,963 5,057 

Wyoming .............................................................................. ........................ ........................ ........................ 9,125 8,573 

(ii) For the control period in 2023, the 

State NOX Ozone Season Group 3 

trading budget for each State shall be 

calculated as the sum of the following 

prorated amounts, rounded to the 

nearest allowance: 

(A) The product of the non-prorated 

trading budget for the portion of the 

2023 control period before [EFFECTIVE 

DATE OF FINAL RULE] shown for the 

State in Table 1 to paragraph (a)(1)(i) of 

this section (or zero if Table 1 shows no 

amount for such portion of the 2023 

control period for the State) multiplied 

by a fraction whose numerator is the 

number of days from May 1, 2023 

through the day before [EFFECTIVE 

DATE OF FINAL RULE], inclusive, and 

whose denominator is 153; and 

(B) The product of the non-prorated 

trading budget for the portion of the 

2023 control period on and after 

[EFFECTIVE DATE OF FINAL RULE] 

shown for the State in Table 1 to 

paragraph (a)(1)(i) of this section 

multiplied by a fraction whose 

numerator is the number of days from 

[EFFECTIVE DATE OF FINAL RULE] 

through September 30, 2023, inclusive, 

and whose denominator is 153. 

(2) The State NOX Ozone Season 

Group 3 trading budget for each State 

and each control period in 2025 and 

thereafter shall be the amount provided 

for the State and control period in the 

applicable notice of data availability 

issued under paragraph (a)(3)(v)(C) of 

this section. 

(3) The Administrator will calculate 

the State NOX Ozone Season Group 3 

trading budget for each State and each 

control period in 2025 and thereafter in 

the year before the year of the control 

period as follows: 

(i) The State’s trading budget for the 

control period shall be calculated as the 

sum (converted to tons at a conversion 

factor of 2,000 lb/ton and rounded to the 

nearest ton), for all units identified for 

inclusion in the calculation under 

paragraph (a)(3)(ii) of this section, of the 

product for each such unit of the NOX

emissions rate in lb/mmBtu identified 

for the unit under paragraph (a)(3)(iii) of 

this section multiplied by the heat input 

in mmBtu identified for the unit under 

paragraph (a)(3)(iv) of this section. 

(ii) A unit in a State (and Indian 

country within the borders of the State) 

shall be included in the calculation of 

the State’s trading budget for a control 

period if: 

(A) The unit was included in the 

calculation of the State’s trading budget 

for the immediately preceding control 

period; or 

(B) The unit’s deadline for 

certification of monitoring systems 

under § 97.1030(b) is on or before May 

1 of the year two years before the year 

of the control period (e.g., May 1, 2023 

for calculation of the trading budget for 

the control period in 2025); 

(C) Provided that a unit shall not be 

included in the calculation of a State’s 

trading budget for a control period if, 

before completing such calculation, the 

Administrator determines that the unit 

is not actually a CSAPR NOX Ozone 

Season Group 3 unit. 

(iii) For each unit included in the 

calculation of the State’s trading budget 

for a control period, the NOX emissions 

rate in lb/mmBtu used in the calculation 

shall be identified as follows: 

(A) For a unit listed in the table 

entitled ‘‘Dynamic Budget 2023 

Template’’ and ‘‘Dynamic Budget 2026+ 

Template’’ posted at 

www.regulations.gov with docket 

identification number EPA–HQ–OAR– 

2021–0668–[XXXX], the NOX emissions 

rate used in the calculation for the 

control period shall be the NOX

emissions rate shown for the unit and 

control period in the tables. 


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(B) For a unit not listed in the table 

referenced in paragraph (a)(3)(iii)(A) of 

this section, the NOX emissions rate 

used in the calculation for the control 

period shall be identified according to 

the type of unit and the type of fuel 

combusted by the unit during the 

control period beginning May 1 on or 

immediately after the unit’s deadline for 

certification of monitoring systems 

under § 97.1030(b) as follows: 

(1) 0.012 lb/mmBtu, for a combined 

cycle combustion turbine other than an 

integrated coal gasification combined 

cycle unit; 

(2) 0.030 lb/mmBtu, for a simple cycle 

combustion turbine or a boiler 

combusting only fuel oil or gaseous fuel 

(other than coal-derived fuel) during 

such control period; or 

(3) 0.050 lb/mmBtu, for a boiler 

combusting any amount of coal or coalderived fuel during such control period 

or any other unit not covered by 

paragraph (a)(3)(iii)(B)(1) or (2) of this 

section. 

(iv) For each unit included in the 

calculation of the State’s trading budget 

for a control period, the heat input in 

mmBtu used in the calculation shall be 

identified as follows: 

(A) Except as provided in paragraph 

(a)(3)(iv)(B) of this section, the heat 

input used in the calculation for the 

control period shall be the heat input 

reported for the unit for the control 

period in the year two years before the 

year of the control period (e.g., heat 

input reported for the control period in 

2023 shall be used in calculating the 

trading budget for the control period in 

2025). 

(B) If no heat input data were reported 

for the unit for the control period in the 

year two years before the year of the 

control period and the heat input used 

for the unit in calculating the State’s 

trading budget for the control period in 

2024 was an estimate rather than the 

unit’s actual reported heat input for the 

control period in 2021 or an earlier year, 

the same estimated heat input used in 

calculating the State’s trading budget for 

the control period in 2024 shall be used 

in the calculations of the State’s trading 

budgets for the control periods in 2025 

and 2026. 

(v)(A) By March 1, 2024 and March 1 

of each year thereafter, the 

Administrator will calculate the State 

CSAPR NOX Ozone Season Group 3 

trading budget for each State, in 

accordance with paragraph (a)(3)(i) 

through (iv) of this section and 

§§ 97.1006(b)(2) and 97.1030 through 

97.1035, for the control period in the 

year after the year of the applicable 

calculation deadline under this 

paragraph and will promulgate a notice 

of data availability of the results of the 

calculations. 

(B) For each notice of data availability 

required in paragraph (a)(3)(v)(A) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. Objections shall be 

submitted by the deadline specified in 

such notice and shall be limited to 

addressing whether the calculations 

(including the identification of the units 

included in the calculations) are in 

accordance with the provisions 

referenced in paragraph (a)(3)(v)(A) of 

this section. 

(C) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(a)(3)(v)(A) of this section. By May 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (a)(3)(v)(A) of this section, 

the Administrator will promulgate a 

notice of data availability of the results 

of the calculations incorporating any 

adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (a)(3)(v)(B) of this section. 

(b) New unit set-asides. (1) The States’ 

new unit set-asides for allocations of 

CSAPR NOX Ozone Season Group 3 

allowances for the control periods in 

2021, 2022, 2023, and 2024 are as 

indicated in Table 2 to this paragraph: 

TABLE 2 TO PARAGRAPH (b)(1)—NEW UNIT SET-ASIDES BY CONTROL PERIOD

[Tons] 

State 2021 2022 2023 2024 

Alabama ........................................................................................................... ........................ ........................ 191 189 

Arkansas .......................................................................................................... ........................ ........................ 178 178 

Delaware .......................................................................................................... ........................ ........................ 54 61 

Illinois ............................................................................................................... 265 265 368 373 

Indiana ............................................................................................................. 262 254 223 188 

Kentucky .......................................................................................................... 309 283 233 233 

Louisiana .......................................................................................................... 430 430 186 186 

Maryland .......................................................................................................... 135 115 24 24

Michigan ........................................................................................................... 500 482 429 429 

Minnesota ........................................................................................................ ........................ ........................ 78 78 

Mississippi ........................................................................................................ ........................ ........................ 100 88 

Missouri ............................................................................................................ ........................ ........................ 237 237 

Nevada ............................................................................................................. ........................ ........................ 137 142 

New Jersey ...................................................................................................... 27 27 16 16 

New York ......................................................................................................... 168 168 188 188 

Ohio ................................................................................................................. 291 290 418 418 

Oklahoma ......................................................................................................... ........................ ........................ 205 191 

Pennsylvania .................................................................................................... 335 339 266 266

Tennessee ....................................................................................................... ........................ ........................ 85 85 

Texas ............................................................................................................... ........................ ........................ 766 766 

Utah ................................................................................................................. ........................ ........................ 449 454 

Virginia ............................................................................................................. 185 161 155 141 

West Virginia .................................................................................................... 266 261 250 250 

Wisconsin ......................................................................................................... ........................ ........................ 119 101 

Wyoming .......................................................................................................... ........................ ........................ 274 257 


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(2) The new unit set-aside for 

allocations of CSAPR NOX Ozone 

Season Group 3 allowances for each 

State for each control period in 2025 

and thereafter shall be calculated as the 

product (rounded to the nearest 

allowance) of the State NOX Ozone 

Season Group 3 trading budget 

determined for the State and control 

period under paragraph (a)(2) of this 

section multiplied by 0.02. 

(c) Indian country new unit set-asides 

for the control periods in 2021 and 

2022. The States’ Indian country new 

unit set-asides for allocations of CSAPR 

NOX Ozone Season Group 3 allowances 

for the control periods in 2021 and 2022 

are as indicated in Table 3 to this 

paragraph: 

TABLE 3 TO PARAGRAPH (c)—INDIAN

COUNTRY NEW UNIT SET-ASIDES BY

CONTROL PERIOD

[Tons] 

State 2021 2022 

Alabama .................... ................ ................

Arkansas ................... ................ ................

Delaware ................... ................ ................

Illinois ........................ ................ ................

Indiana ...................... ................ ................

Kentucky ................... ................ ................

Louisiana .................. 15 15 

Maryland ................... ................ ................

Michigan ................... 13 12 

Minnesota ................. ................ ................

Mississippi ................ ................ ................

Missouri .................... ................ ................

Nevada ..................... ................ ................

New Jersey ............... ................ ................

New York .................. 3 3 

Ohio .......................... ................ ................

Oklahoma ................. ................ ................

Pennsylvania ............ ................ ................

Tennessee ................ ................ ................

Texas ........................ ................ ................

Utah .......................... ................ ................

Virginia ...................... ................ ................

West Virginia ............ ................ ................

Wisconsin ................. ................ ................

Wyoming ................... ................ ................

(d) Indian country existing unit setasides 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 § 97.1011(a)(2). 

(e) Variability limits. (1) The 

variability limit for the State NOX Ozone 

Season Group 3 trading budget for each 

State for each control period from 2021 

through 2024 shall be calculated as the 

product (rounded to the nearest ton) of 

the State NOX Ozone Season Group 3 

trading budget determined for the State 

and control period in accordance with 

paragraph (a)(1) of this section 

multiplied by 0.21. 

(2) The variability limit for the State 

NOX Ozone Season Group 3 trading 

budget for each State for each control 

period in 2025 and thereafter shall be 

calculated as the product (rounded to 

the nearest ton) of the State NOX Ozone 

Season Group 3 trading budget 

determined for the State and control 

period in accordance with paragraph 

(a)(2) of this section multiplied by the 

greater of: 

(i) 0.21; or 

(ii) Any excess over 1.00 of the 

quotient (rounded to two decimal 

places) of the total heat input reported 

for the control period for all CSAPR 

NOX Ozone Season Group 3 units in the 

State and Indian country within the 

borders of the State divided by the total 

heat input used in the calculation of the 

State’s trading budget for the control 

period under paragraph (a)(3) of this 

section. 

(f) Relationship of trading budgets, 

set-asides, and variability limits. Each 

State NOX Ozone Season Group 3 

trading budget in this section includes 

any tons in a new unit set-aside, Indian 

country new unit set-aside, or Indian 

country existing unit set-aside but does 

not include any tons in a variability 

limit. 

■ 74. Amend § 97.1011 by revising the 

section heading and paragraphs (a), (b), 

and (c)(1) and (5) to read as follows: 

§ 97.1011 CSAPR NOX Ozone Season 

Group 3 allowance allocations to existing 

units. 

(a) Allocations to existing units in 

general. (1) For the control periods in 

2021 and each year thereafter, CSAPR 

NOX Ozone Season Group 3 allowances 

will be allocated to units in each State 

and areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority as provided in notices of 

data availability issued by the 

Administrator. Starting with the control 

period in 2025, the notices of data 

availability will be the notices issued 

under paragraph (b)(10)(iii) of this 

section. 

(2) For the control periods in 2023 

and each year thereafter, CSAPR NOX

Ozone Season Group 3 allowances will 

be allocated to units in areas of Indian 

country within the borders of each State 

not subject to the State’s SIP authority 

as provided in notices of data 

availability issued by the Administrator. 

Starting with the control period in 2025, 

the notices of data availability will be 

the notices issued under paragraph 

(b)(10)(iii) of this section. 

(3) Providing an allocation to a unit in 

a notice of data availability does not 

constitute a determination that the unit 

is a CSAPR NOX Ozone Season Group 

3 unit, and not providing an allocation 

to a unit in such notice does not 

constitute a determination that the unit 

is not a CSAPR NOX Ozone Season 

Group 3 unit. 

(b) Calculation of default allocations 

to existing units for control periods in 

2025 and thereafter. For each control 

period in 2025 and thereafter, and for 

the CSAPR NOX Ozone Season Group 3 

units in each State and areas of Indian 

country within the borders of the State, 

the Administrator will calculate default 

allocations of CSAPR NOX Ozone 

Season Group 3 allowances to the 

CSAPR NOX Ozone Season Group 3 

units as follows: 

(1) For each State and control period, 

the total amount of CSAPR NOX Ozone 

Season Group 3 allowances for which 

default allocations will be calculated 

will be the remainder of the State NOX

Ozone Season Group 3 trading budget 

for the control period under 

§ 97.1010(a)(2) minus the new unit setaside for the control period under 

§ 97.1010(b)(2). 

(2) A default allocation of CSAPR 

NOX Ozone Season Group 3 allowances 

will be calculated for a CSAPR NOX

Ozone Season Group 3 unit in the State 

and Indian country within the borders 

of the State for a control period if: 

(i) The unit meets the conditions 

under § 97.1010(a)(3)(ii) to be included 

in the calculation of the State’s trading 

budget for the control period; and 

(ii) The unit reported heat input 

greater than zero for the control period 

in the year two years before the year of 

the control period. 

(3) For each CSAPR NOX Ozone 

Season Group 3 unit for which a default 

allocation is being calculated for a 

control period, the Administrator will 

determine the following amounts for the 

five-year historical period ending with 

the year two years before the year of the 

control period for which default 

allocations are being calculated: 

(i) The total heat input reported for 

the unit in accordance with part 75 of 

this chapter for the control period in 

each year of the five-year historical 

period; 

(ii) The average of the three highest of 

the total heat input values determined 

for the unit under paragraph (b)(3)(i) of 

this section or, if fewer than three nonzero values were determined for the 

unit, the average of all such non-zero 

heat input values; 


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(iii) The total NOX emissions reported 

for the unit in accordance with part 75 

of this chapter for the control period in 

each year of the five-year historical 

period; and 

(iv) The maximum of the total NOX

emissions values determined for the 

unit under paragraph (b)(3)(iii) of this 

section. 

(4) The Administrator will calculate 

the initial unrounded default allocations 

for each CSAPR NOX Ozone Season 

Group 3 unit according to the procedure 

in paragraph (b)(5) of this section and 

will recalculate the unrounded default 

allocations according to the procedures 

in paragraph (b)(6) or (7) of this section, 

as applicable, iterating the 

recalculations as necessary until the 

total of the unrounded default 

allocations to all eligible units equals 

the amount of allowances determined 

for the State under paragraph (b)(1) of 

this section. 

(5) The Administrator will calculate 

the initial unrounded default allocations 

to CSAPR NOX Ozone Season Group 3 

units as follows: 

(i) The Administrator will calculate 

the sum, for all units determined under 

paragraph (b)(2) of this section to be 

eligible to receive a default allocation, of 

the units’ average heat input determined 

under paragraph (b)(3)(ii) of this section. 

(ii) For each unit determined under 

paragraph (b)(2) of this section to be 

eligible to receive a default allocation, 

the Administrator will calculate the 

unit’s unrounded default allocation as 

the lesser of: 

(A) The product of the total amount 

of allowances determined for the State 

and control period under paragraph 

(b)(1) of this section multiplied by a 

fraction whose numerator is the unit’s 

average heat input determined under 

paragraph (b)(3)(ii) of this section and 

whose denominator is the sum 

determined under paragraph (b)(5)(i) of 

this section; and 

(B) The unit’s maximum total NOX

emissions determined under paragraph 

(b)(3)(iv) of this section. 

(iii) If the sum of the unrounded 

default allocations determined under 

paragraph (b)(5)(ii) of this section is less 

than the total amount of allowances 

determined for the State and control 

period under paragraph (b)(1) of this 

section, the Administrator will follow 

the procedures in paragraph (b)(6) or (7) 

of this section, as applicable. 

(iv) If the sum of the unrounded 

default allocations determined under 

paragraph (b)(5)(ii) of this section equals 

the total amount of allowances 

determined for the State and control 

period under paragraph (b)(1) of this 

section, the Administrator will 

determine the rounded default 

allocations according to the procedures 

in paragraphs (b)(8) and (9) of this 

section. 

(6) If the unrounded default allocation 

determined in the previous round of the 

calculation procedure for at least one 

CSAPR NOX Ozone Season Group 3 unit 

is less than the unit’s maximum total 

NOX emissions determined under 

paragraph (b)(3)(iv) of this section, the 

Administrator will recalculate the 

unrounded default allocations as 

follows: 

(i) The Administrator will calculate 

the additional pool of allowances to be 

allocated as the remainder of the total 

amount of allowances determined for 

the State and control period under 

paragraph (b)(1) of this section minus 

the sum of the unrounded default 

allocations from the previous round of 

the calculation procedure for all units 

determined under paragraph (b)(2) of 

this section to be eligible to receive a 

default allocation. 

(ii) The Administrator will calculate 

the sum, for all units whose unrounded 

default allocations determined in the 

previous round of the calculation 

procedure were less than the respective 

units’ maximum total NOX emissions 

determined under paragraph (b)(3)(iv) of 

this section, of the units’ average heat 

input determined under paragraph 

(b)(3)(ii) of this section. 

(iii) For each unit whose unrounded 

default allocation determined in the 

previous round of the calculation was 

less than the unit’s maximum total NOX

emissions determined under paragraph 

(b)(3)(iv) of this section, the 

Administrator will recalculate the unit’s 

unrounded default allocation, before 

rounding, as the lesser of: 

(A) The sum of the unit’s unrounded 

default allocation determined in the 

previous round of the calculation 

procedure plus the product of the 

additional pool of allowances 

determined under paragraph (b)(6)(i) of 

this section multiplied by a fraction 

whose numerator is the unit’s average 

heat input determined under paragraph 

(b)(3)(ii) of this section and whose 

denominator is the sum determined 

under paragraph (b)(6)(ii) of this section; 

and 

(B) The unit’s maximum total NOX

emissions determined under paragraph 

(b)(3)(iv) of this section. 

(iv) Except as provided in paragraph 

(b)(6)(iii) of this section, a unit’s 

unrounded default allocation shall 

equal the amount determined in the 

previous round of the calculation 

procedure. 

(v) If the sum of the unrounded 

default allocations determined under 

paragraphs (b)(6)(iii) and (iv) of this 

section is less than the total amount of 

allowances determined for the State and 

control period under paragraph (b)(1) of 

this section, the Administrator will 

iterate the procedures in paragraph 

(b)(6) of this section or follow the 

procedures in paragraph (b)(7) of this 

section, as applicable. 

(vi) If the sum of the unrounded 

default allocations determined under 

paragraphs (b)(6)(iii) and (iv) of this 

section equals the total amount of 

allowances determined for the State and 

control period under paragraph (b)(1) of 

this section, the Administrator will 

determine the rounded default 

allocations according to the procedures 

in paragraphs (b)(8) and (9) of this 

section. 

(7) If the unrounded default allocation 

determined in the previous round of the 

calculation procedure for every CSAPR 

NOX Ozone Season Group 3 unit equals 

the unit’s maximum total NOX

emissions determined under paragraph 

(b)(3)(iv) of this section, the 

Administrator will recalculate the 

unrounded default allocations as 

follows: 

(i) The Administrator will calculate 

the additional pool of allowances to be 

allocated as the remainder of the total 

amount of allowances determined for 

the State and control period under 

paragraph (b)(1) of this section minus 

the sum of the unrounded default 

allocations from the previous round for 

all units determined under paragraph 

(b)(2) of this section to be eligible to 

receive a default allocation. 

(ii) The Administrator will recalculate 

the unrounded default allocation for 

each eligible unit as the sum of: 

(A) The unit’s unrounded default 

allocation as determined in the previous 

round of the calculation procedure; plus 

(B) The product of the additional pool 

of allowances determined under 

paragraph (b)(7)(i) of this section 

multiplied by a fraction whose 

numerator is the unit’s average heat 

input determined under paragraph 

(b)(3)(ii) of this section and whose 

denominator is the sum determined 

under paragraph (b)(5)(i) of this section. 

(8) The Administrator will round the 

default allocation for each eligible unit 

determined under paragraph (b)(5), (6), 

or (7) of this section to the nearest 

allowance and make any adjustments 

required under paragraph (b)(9) of this 

section. 

(9) If the sum of the default 

allocations after rounding under 

paragraph (b)(8) of this section does not 

equal the total amount of allowances 

determined for the State and control 

period under paragraph (b)(1) of this 


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section, the Administrator will adjust 

the default allocations as follows. The 

Administrator will list the CSAPR NOX

Ozone Season Group 3 units in 

descending order based on such units’ 

allocation amounts under paragraph 

(b)(8) of this section and, in cases of 

equal allocation amounts, in 

alphabetical order of the relevant 

sources’ names and numerical order of 

the relevant units’ identification 

numbers, and will adjust each unit’s 

allocation amount upward or downward 

by one CSAPR NOX Ozone Season 

Group 3 allowance (but not below zero) 

in the order in which the units are 

listed, and will repeat this adjustment 

process as necessary, until the total of 

the adjusted default allocations equals 

the total amount of allowances 

determined for the State and control 

period under paragraph (b)(1) of this 

section. 

(10)(i) By March 1, 2024 and March 1 

of each year thereafter, the 

Administrator will calculate the default 

allocation of CSAPR NOX Ozone Season 

Group 3 allowances to each CSAPR NOX

Ozone Season Group 3 unit in a State 

and Indian country within the borders 

of the State, in accordance with 

paragraphs (b)(1) through (9) of this 

section and §§ 97.1006(b)(2) and 

97.1030 through 97.1035, for the control 

period in the year after the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of data availability of the results 

of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(10)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. Objections shall be 

submitted by the deadline specified in 

such notice of data availability and shall 

be limited to addressing whether the 

calculations (including the 

identification of the CSAPR NOX Ozone 

Season Group 3 units) are in accordance 

with the provisions referenced in 

paragraph (b)(10)(i) of this section. 

(iii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(10)(i) of this section. By May 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(10)(i) of this section, 

the Administrator will promulgate a 

notice of data availability of the results 

of the calculations incorporating any 

adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(10)(ii) of this section. 

(c) Incorrect allocations of CSAPR 

NOX Ozone Season Group 3 allowances 

to existing units. (1) For each control 

period in 2021 and thereafter, if the 

Administrator determines that CSAPR 

NOX Ozone Season Group 3 allowances 

were allocated for the control period to 

a recipient covered by the provisions of 

paragraph (c)(1)(i), (ii), or (iii) of this 

section, then the Administrator will 

notify the designated representative of 

the recipient and will act in accordance 

with the procedures set forth in 

paragraphs (c)(2) through (5) of this 

section: 

(i) The recipient is not actually a 

CSAPR NOX Ozone Season Group 3 unit 

under § 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 § 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 § 52.38(b)(10), (11), or (12) of this 

chapter that the SIP revision provides 

should be allocated only to recipients 

that are CSAPR NOX Ozone Season 

Group 3 units as of the first day of such 

control period; or 

(iii) The recipient is not located as of 

the first day of the control period in the 

State (and Indian country within the 

borders of the State) from whose NOX

Ozone Season Group 3 trading budget 

the CSAPR NOX Ozone Season Group 3 

allowances allocated under paragraph 

(a)(1) or (2) of this section, or under a 

provision of a SIP revision approved 

under § 52.38(b)(10), (11), or (12) of this 

chapter, were allocated for such control 

period. 

* * * * * 

(5) With regard to any CSAPR NOX

Ozone Season Group 3 allowances that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section: 

(i) If the non-recordation decision 

under paragraph (c)(2) of this section or 

the deduction under paragraph (c)(3) of 

this section occurs on or before May 1, 

2024, the Administrator will transfer the 

CSAPR NOX Ozone Season Group 3 

allowances to the new unit set-aside for 

2021, 2022, or 2023 for the State from 

whose NOX Ozone Season Group 3 

trading budget the CSAPR NOX Ozone 

Season Group 3 allowances were 

allocated. 

(ii) If the non-recordation decision 

under paragraph (c)(2) of this section or 

the deduction under paragraph (c)(3) of 

this section occurs after May 1, 2024 

and on or before May 1 of the year 

following the year of the control period 

for which the CSAPR NOX Ozone 

Season Group 3 allowances were 

allocated, the Administrator will 

transfer the CSAPR NOX Ozone Season 

Group 3 allowances to the new unit setaside 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. 

■ 75. Amend § 97.1012 by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(1)(i) and (ii); 

■ b. Removing paragraphs (a)(1)(iii) and 

(iv); 

■ c. Revising paragraphs (a)(2) and 

(a)(3)(i); 

■ d. In paragraph (a)(3)(ii), adding 

‘‘and’’ after the semicolon; 

■ e. Revising paragraph (a)(3)(iii); 

■ f. Removing paragraph (a)(3)(iv); 

■ g. Revising paragraphs (a)(5) and (10): 

■ h. In paragraph (a)(11), removing 

‘‘§ 97.1011(b)(1)(i), (ii), and (v), of’’ and 

adding in its place ‘‘paragraph (a)(13) of 

this section, of’’; 

■ i. Adding paragraph (a)(13); 

■ j. Revising paragraphs (b) introductory 

text and (b)(1) and (2); 

■ k. In paragraph (b)(5), removing 

‘‘Indian country within the borders of 

the State’’ and adding in its place ‘‘areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority’’; 

■ l. Revising paragraph (b)(10); 

■ m. In paragraph (b)(11), removing 

‘‘§ 97.1011(b)(2)(i), (ii), and (v), of’’ and 

adding in its place ‘‘paragraph (b)(13) of 

this section, of’’; and 

■ n. Adding paragraphs (b)(13) and (c). 

The revisions and additions read as 

follows: 

§ 97.1012 CSAPR NOX Ozone Season 

Group 3 allowance allocations to new units. 

(a) Allocations from new unit setasides. For each control period in 2021 

and thereafter for a State listed in 

§ 52.38(b)(2)(iii)(A) of this chapter, or 

2023 and thereafter for a State listed in 

§ 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 


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20212 Federal Register / Vol. 87, No. 66 / Wednesday, April 6, 2022 / Proposed Rules 

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 § 97.1011(a)(1) or (2) and 

that have deadlines for certification of 

monitoring systems under § 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 § 97.1011(a)(1) or (2) is 

covered by § 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 § 97.1010(b) 

and will be allocated additional CSAPR 

NOX Ozone Season Group 3 allowances 

(if any) in accordance with 

§ 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 § 52.38(b)(2)(iii)(A) of this 

chapter, or the control period in 2023, 

for a State listed in § 52.38(b)(2)(iii)(B) 

or (C) of this chapter; 

* * * * * 

(iii) For a unit described in paragraph 

(a)(1)(ii) of this section, the first control 

period in which the CSAPR NOX Ozone 

Season Group 3 unit operates in the 

State and Indian country within the 

borders of the State (except, for the 

control periods in 2021 and 2022, areas 

of Indian country within the borders of 

the State not subject to the State’s SIP 

authority) after operating in another 

jurisdiction and for which the unit is 

not already allocated one or more 

CSAPR NOX Ozone Season Group 3 

allowances. 

* * * * * 

(5) The Administrator will calculate 

the sum of the allocation amounts of 

CSAPR NOX Ozone Season Group 3 

allowances determined for all such 

CSAPR NOX Ozone Season Group 3 

units under paragraph (a)(4)(i) of this 

section in the State and Indian country 

within the borders of the State (except, 

for the control periods in 2021 and 

2022, areas of Indian country within the 

borders of the State not subject to the 

State’s SIP authority) for such control 

period. 

* * * * * 

(10)(i) For a control period in 2021 or 

2022, if, after completion of the 

procedures under paragraphs (a)(2) 

through (7) and (12) of this section for 

a control period, any unallocated 

CSAPR NOX Ozone Season Group 3 

allowances remain in the new unit setaside for the State for such control 

period, the Administrator will allocate 

to each CSAPR NOX Ozone Season 

Group 3 unit that is in the State and 

areas of Indian country within the 

borders of the State subject to the State’s 

SIP authority and is allocated an 

amount of CSAPR NOX Ozone Season 

Group 3 allowances for the control 

period in the applicable notice of data 

availability referenced in § 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 

§ 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 setaside 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 

§ 97.1011(a)(1) or (2), or under a 

provision of a SIP revision approved 

under § 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 

§ 97.1011(a)(1) or (2) or a provision of a 

SIP revision approved under 

§ 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 setaside 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 

§§ 97.1006(b)(2) and 97.1030 through 

97.1035, for the control period in the 

year before the year of the applicable 

calculation deadline under this 

paragraph and will promulgate a notice 

of data availability of the results of the 

calculations. 

(ii) For each notice of data availability 

required in paragraph (a)(13)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. Objections shall be 

submitted by the deadline specified in 

such notice and shall be limited to 

addressing whether the calculations 

(including the identification of the 

CSAPR NOX Ozone Season Group 3 

units) are in accordance with the 

provisions referenced in paragraph 

(a)(13)(i) of this section. 

(iii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(a)(13)(i) of this section. By May 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (a)(13)(i) of this section, 

the Administrator will promulgate a 

notice of data availability of the results 

of the calculations incorporating any 

adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (a)(13)(ii) of this section. 

(b) Allocations from Indian country 

new unit set-asides. For the control 

periods in 2021 and 2022, for a State 

listed in § 52.38(b)(2)(iii)(A) of this 

chapter, and for the CSAPR NOX Ozone 


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Season Group 3 units in areas of Indian 

country within the borders of each such 

State not subject to the State’s SIP 

authority, the Administrator will 

allocate CSAPR NOX Ozone Season 

Group 3 allowances to the CSAPR NOX

Ozone Season Group 3 units as follows: 

(1) The CSAPR NOX Ozone Season 

Group 3 allowances will be allocated to 

CSAPR NOX Ozone Season Group 3 

units that are not allocated an amount 

of CSAPR NOX Ozone Season Group 3 

allowances for such control period in 

the applicable notice of data availability 

issued under § 97.1011(a)(1) and that 

have deadlines for certification of 

monitoring systems under § 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 setaside 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 § 97.1010(c) and will be 

allocated additional CSAPR NOX Ozone 

Season Group 3 allowances (if any) in 

accordance with paragraph (c)(5) of this 

section. 

* * * * * 

(10) If, after completion of the 

procedures under paragraphs (b)(2) 

through (7) and (12) of this section for 

a control period, any unallocated 

CSAPR NOX Ozone Season Group 3 

allowances remain in the Indian country 

new unit set-aside for the State for such 

control period, the Administrator will 

transfer such unallocated CSAPR NOX

Ozone Season Group 3 allowances to 

the new unit set-aside for the State for 

such control period. 

* * * * * 

(13)(i) By March 1, 2022 and March 1, 

2023, the Administrator will calculate 

the CSAPR NOX Ozone Season Group 3 

allowance allocation to each CSAPR 

NOX Ozone Season Group 3 unit in 

areas of Indian country within the 

borders of a State not subject to the 

State’s SIP authority, in accordance with 

paragraphs (b)(2) through (7), (10), and 

(12) of this section and §§ 97.1006(b)(2) 

and 97.1030 through 97.1035, for the 

control period in the year before the 

year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of data availability 

of the results of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(13)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. Objections shall be 

submitted by the deadline specified in 

such notice and shall be limited to 

addressing whether the calculations 

(including the identification of the 

CSAPR NOX Ozone Season Group 3 

units) are in accordance with the 

provisions referenced in paragraph 

(b)(13)(i) of this section. 

(iii) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(13)(i) of this section. By May 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(13)(i) of this section, 

the Administrator will promulgate a 

notice of data availability of the results 

of the calculations incorporating any 

adjustments that the Administrator 

determines to be necessary and the 

reasons for accepting or rejecting any 

objections submitted in accordance with 

paragraph (b)(13)(ii) of this section. 

(c) Incorrect allocations of CSAPR 

NOX Ozone Season Group 3 allowances 

to new units. (1) For each control period 

in 2021 and thereafter, if the 

Administrator determines that CSAPR 

NOX Ozone Season Group 3 allowances 

were allocated for the control period 

under paragraphs (a)(2) through (7) and 

(12) of this section or paragraphs (b)(2) 

through (7) and (12) of this section to a 

recipient that is not actually a CSAPR 

NOX Ozone Season Group 3 unit under 

§ 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 § 97.1021. 

(3) If the Administrator already 

recorded such CSAPR NOX Ozone 

Season Group 3 allowances under 

§ 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 

§ 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 

§ 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 

§ 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. 

■ 76. Amend § 97.1021 by: 

■ a. In paragraph (a), removing 

‘‘§ 97.1011(a)’’ and adding in its place 

‘‘§ 97.1011(a)(1)’’; 

■ b. Revising paragraph (b); 

■ c. Removing and reserving paragraph 

(c); 

■ d. Revising paragraph (d); 

■ e. Adding paragraph (e); 

■ f. Revising paragraphs (f) and (g); 


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■ g. In paragraph (h), removing ‘‘May 1 

of each year thereafter, the’’ and adding 

in its place ‘‘May 1, 2023, the’’; 

■ h. Adding paragraphs (i) and (j); and 

■ i. In paragraph (m), adding ‘‘or (e)’’ 

after ‘‘§ 97.811(d)’’ each time it appears. 

The revisions and addition read as 

follows: 

§ 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 § 97.1011(a)(1) for the 

control period in 2022. 

* * * * * 

(d) By [30 DAYS AFTER EFFECTIVE 

DATE OF FINAL RULE], the 

Administrator will record in each 

CSAPR NOX Ozone Season Group 3 

source’s compliance account the CSAPR 

NOX Ozone Season Group 3 allowances 

allocated to the CSAPR NOX Ozone 

Season Group 3 units at the source in 

accordance with § 97.1011(a)(1) for the 

control period in 2023. 

(e) By [30 DAYS AFTER EFFECTIVE 

DATE OF FINAL RULE], the 

Administrator will record in each 

CSAPR NOX Ozone Season Group 3 

source’s compliance account the CSAPR 

NOX Ozone Season Group 3 allowances 

allocated to the CSAPR NOX Ozone 

Season Group 3 units at the source in 

accordance with § 97.1011(a)(1) for the 

control period in 2024, unless the State 

in which the source is located notifies 

the Administrator in writing by 

[EFFECTIVE DATE OF FINAL RULE] of 

the State’s intent to submit to the 

Administrator a complete SIP revision 

by September 1, 2023 meeting the 

requirements of § 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 

§ 97.1011(a)(1) for the control period in 

2024. 

(2) If the State submits to the 

Administrator by September 1, 2023 and 

the Administrator approves by March 1, 

2024 such complete SIP revision, the 

Administrator will record by March 1, 

2024 in each CSAPR NOX Ozone Season 

Group 3 source’s compliance account 

the CSAPR NOX Ozone Season Group 3 

allowances allocated to the CSAPR NOX

Ozone Season Group 3 units at the 

source as provided in such approved, 

complete SIP revision for the control 

period in 2024. 

(3) If the State submits to the 

Administrator by September 1, 2023 and 

the Administrator does not approve by 

March 1, 2024 such complete SIP 

revision, the Administrator will record 

by March 1, 2024 in each CSAPR NOX

Ozone Season Group 3 source’s 

compliance account the CSAPR NOX

Ozone Season Group 3 allowances 

allocated to the CSAPR NOX Ozone 

Season Group 3 units at the source in 

accordance with § 97.1011(a)(1) for the 

control period in 2024. 

(f) By July 1, 2024 and July 1 of each 

year thereafter, the Administrator will 

record in each CSAPR NOX Ozone 

Season Group 3 source’s compliance 

account the CSAPR NOX Ozone Season 

Group 3 allowances allocated to the 

CSAPR NOX Ozone Season Group 3 

units at the source, or in each 

appropriate Allowance Management 

System account the CSAPR NOX Ozone 

Season Group 3 allowances auctioned to 

CSAPR NOX Ozone Season Group 3 

units, in accordance with 

§ 97.1011(a)(1), or with a SIP revision 

approved under § 52.38(b)(11) or (12) of 

this chapter, for the control period in 

the year after the year of the applicable 

recordation deadline under this 

paragraph. 

(g) By May 1, 2022 and May 1 of each 

year thereafter, the Administrator will 

record in each CSAPR NOX Ozone 

Season Group 3 source’s compliance 

account the CSAPR NOX Ozone Season 

Group 3 allowances allocated to the 

CSAPR NOX Ozone Season Group 3 

units at the source in accordance with 

§ 97.1012(a) for the control period in the 

year before the year of the applicable 

recordation deadline under this 

paragraph. 

* * * * * 

(i) By [30 DAYS AFTER EFFECTIVE 

DATE OF FINAL RULE], the 

Administrator will record in each 

CSAPR NOX Ozone Season Group 3 

source’s compliance account the CSAPR 

NOX Ozone Season Group 3 allowances 

allocated to the CSAPR NOX Ozone 

Season Group 3 units at the source in 

accordance with § 97.1011(a)(2) for the 

control periods in 2023 and 2024. 

(j) By July 1, 2024 and July 1 of each 

year thereafter, the Administrator will 

record in each CSAPR NOX Ozone 

Season Group 3 source’s compliance 

account the CSAPR NOX Ozone Season 

Group 3 allowances allocated to the 

CSAPR NOX Ozone Season Group 3 

units at the source in accordance with 

§ 97.1011(a)(2) for the control period in 

the year after the year of the applicable 

recordation deadline under this 

paragraph. 

* * * * * 

■ 77. Amend § 97.1024 by: 

■ a. Revising the section heading; 

■ b. In paragraphs (a) introductory text 

and (b) introductory text, adding 

‘‘primary’’ before ‘‘emissions 

limitation’’; 

■ c. Revising paragraph (b)(1); 

■ d. Adding paragraph (b)(3); and 

■ e. In paragraph (c)(2)(ii), adding ‘‘or 

(e)’’ after ‘‘§ 97.826(d)’’. 

The revisions and addition read as 

follows: 

§ 97.1024 Compliance with CSAPR NOX

Ozone Season Group 3 primary emissions 

limitation. 

* * * * * 

(b) * * * 

(1) Until the amount of CSAPR NOX

Ozone Season Group 3 allowances 

deducted equals the sum of: 

(i) The number of tons of total NOX

emissions from all CSAPR NOX Ozone 

Season Group 3 units at the source for 

such control period; plus 

(ii) Two times the sum (converted to 

tons at a conversion factor of 2,000 lb/ 

ton and rounded to the nearest ton), for 

all days in the control period and all 

CSAPR NOX Ozone Season Group 3 

units at the source to which backstop 

daily NOX emissions rates apply for the 

control period under paragraph (b)(3) of 

this section, of any amount by which a 

unit’s NOX emissions for a given day in 

pounds exceed the product in pounds of 

the unit’s total heat input in mmBtu for 

that day multiplied by the applicable 

backstop daily NOX emissions rate in lb/ 

mmBtu; or 

* * * * * 

(3) The applicable backstop daily NOX

emissions rates are as follows: 

(i) For the control periods in 2024 and 

each year thereafter, a backstop daily 

NOX emissions rate of 0.14 lb/mmBtu 

shall apply to each CSAPR NOX Ozone 

Season Group 3 unit combusting any 

coal during the control period, serving 

a generator with nameplate capacity of 

100 MW or more, and equipped with 

selective catalytic reduction controls, 

except a circulating fluidized bed boiler. 

(ii) For the control periods in 2027 

and each year thereafter, a backstop 

daily NOX emissions rate of 0.14 lb/ 

mmBtu shall apply to each CSAPR NOX

Ozone Season Group 3 unit combusting 

any coal during the control period and 

serving a generator with nameplate 


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capacity of 100 MW or more, except a 

circulating fluidized bed boiler. 

* * * * * 

■ 78. Amend § 97.1025 by revising the 

section heading and adding paragraph 

(c) to read as follows: 

§ 97.1025 Compliance with CSAPR NOX

Ozone Season Group 3 assurance 

provisions; CSAPR NOX Ozone Season 

Group 3 secondary emissions limitation. 

* * * * * 

(c) CSAPR NOX Ozone Season Group 

3 secondary emissions limitation. (1) 

The owner or operator of a base CSAPR 

NOX Ozone Season Group 3 unit shall 

not discharge, or allow to be discharged, 

emissions of NOX to the atmosphere 

during a control period in excess of the 

tonnage amount calculated in 

accordance with paragraph (c)(2) of this 

section, provided that the emissions 

limitation established under this 

paragraph shall apply to a unit for a 

control period only if: 

(i) The unit is included for the control 

period in a group of base CSAPR NOX

Ozone Season Group 3 units at base 

CSAPR NOX Ozone Season Group 3 

sources in a State (and Indian country 

within the borders of such State) having 

a common designated representative 

and the owners and operators of such 

units and sources are subject to a 

requirement for such control period to 

hold one or more CSAPR NOX Ozone 

Season Group 3 allowances under 

§ 97.1006(c)(2)(i) and paragraph (b) of 

this section with respect to such group; 

and 

(ii) The unit was required to report 

NOX emissions and heat input data for 

all or portions of at least 367 operating 

hours during the control period and all 

or portions of at least 367 operating 

hours during at least one previous 

control period under the CSAPR NOX

Ozone Season Group 1 Trading 

Program, CSAPR NOX Ozone Season 

Group 2 Trading Program, or CSAPR 

NOX Ozone Season Group 3 Trading 

Program. 

(2) The amount of the emissions 

limitation applicable to a base CSAPR 

NOX Ozone Season Group 3 unit for a 

control period under paragraph (c)(1) of 

this section, in tons of NOX, shall be 

calculated as the sum of 50 plus the 

product (converted to tons at a 

conversion factor of 2,000 lb/ton and 

rounded to the nearest ton) of 

multiplying— 

(i) The total heat input in mmBtu 

reported for the unit for the control 

period in accordance with §§ 97.1030 

through 97.1035; and 

(ii) A NOX emission rate of 0.10 lb/ 

mmBtu or, if higher, the product of 1.25 

times the lowest seasonal average NOX

emission rate in lb/mmBtu achieved by 

the unit in any previous control period 

for which the unit was required to 

report NOX emissions and heat input 

data for all or portions of at least 367 

operating hours under the CSAPR NOX

Ozone Season Group 1 Trading 

Program, CSAPR NOX Ozone Season 

Group 2 Trading Program, or CSAPR 

NOX Ozone Season Group 3 Trading 

Program, where the unit’s seasonal 

average NOX emission rate for each such 

previous control period shall be 

calculated from such reported data as 

the quotient of the unit’s total NOX

emissions in tons for the control period 

divided by the unit’s total heat input in 

mmBtu for the control period, 

multiplied by a conversion factor of 

2,000 lb/ton, and rounded to the nearest 

0.0001 lb/mmBtu. 

■ 79. Amend § 97.1026 by: 

■ a. Revising paragraph (b); 

■ b. In paragraph (c), removing ‘‘State 

(or Indian’’ and adding in its place 

‘‘State (and Indian’’; and 

■ c. Adding paragraph (d). 

The revision and addition read as 

follows: 

§ 97.1026 Banking. 

* * * * * 

(b) Any CSAPR NOX Ozone Season 

Group 3 allowance that is held in a 

compliance account or a general 

account will remain in such account 

unless and until the CSAPR NOX Ozone 

Season Group 3 allowance is deducted 

or transferred under § 97.1011(c), 

§ 97.1012(c), § 97.1023, § 97.1024, 

§ 97.1025, § 97.1027, or § 97.1028 or 

paragraph (c) or (d) of this section. 

* * * * * 

(d) Before the allowance transfer 

deadline for each control period in 2024 

or a subsequent year, the Administrator 

will deduct amounts of CSAPR NOX

Ozone Season Group 3 allowances 

issued for the control periods in 

previous years exceeding the CSAPR 

NOX Ozone Season Group 3 allowance 

bank ceiling target for the control period 

in accordance with paragraphs (d)(1) 

through (4) of this section. 

(1) As soon as practicable on or after 

August 1, 2024 and August 1 of each 

subsequent year, the Administrator will 

temporarily suspend acceptance of 

CSAPR NOX Ozone Season Group 3 

allowance transfers submitted under 

§ 97.1022 and, before resuming 

acceptance of such transfers, will take 

the actions in paragraphs (d)(2) through 

(4) of this section. 

(2) The Administrator will determine 

each of the following values: 

(i) The CSAPR NOX Ozone Season 

Group 3 allowance bank ceiling target 

for the control period in the year of the 

deadline under paragraph (d)(1) of this 

section, calculated as the product, 

rounded to the nearest allowance, of 

0.105 times the sum for all States listed 

in § 52.38(b)(2)(iii) of this chapter of the 

State NOX Ozone Season Group 3 

trading budgets under § 97.1010(a) for 

such States for such control period. 

(ii) The total amount of CSAPR NOX

Ozone Season Group 3 allowances 

issued for control periods in years 

before the year of the deadline under 

paragraph (d)(1) of this section and held 

in all compliance and general accounts. 

(3) If the CSAPR NOX Ozone Season 

Group 3 allowance bank ceiling target 

determined under paragraph (d)(2)(i) of 

this section is less than the total amount 

of CSAPR NOX Ozone Season Group 3 

allowances determined under paragraph 

(d)(2)(ii) of this section, then for each 

compliance account or general account 

holding CSAPR NOX Ozone Season 

Group 3 allowances issued for control 

periods in years before the year of the 

deadline under paragraph (d)(1) of this 

section, the Administrator will: 

(i) Determine the total amount of 

CSAPR NOX Ozone Season Group 3 

allowances issued for control periods in 

years before the year of the deadline 

under paragraph (d)(1) of this section 

and held in the account. 

(ii) Determine the account’s share of 

the CSAPR NOX Ozone Season Group 3 

allowance bank ceiling target for the 

control period, calculated as the 

product, rounded up to the nearest 

allowance, of the CSAPR NOX Ozone 

Season Group 3 allowance bank ceiling 

target determined under paragraph 

(d)(2)(i) of this section multiplied by a 

fraction whose numerator is the total 

amount of CSAPR NOX Ozone Season 

Group 3 allowances held in the account 

determined under paragraph (d)(3)(i) of 

this section and whose denominator is 

the total amount of CSAPR NOX Ozone 

Season Group 3 allowances held in all 

compliance and general accounts 

determined under paragraph (d)(2)(ii) of 

this section. 

(iii) Deduct an amount of CSAPR NOX

Ozone Season Group 3 allowances 

issued for control periods in years 

before the year of the deadline under 

paragraph (d)(1) of this section equal to 

any positive remainder of the total 

amount of CSAPR NOX Ozone Season 

Group 3 allowances held in the account 

determined under paragraph (d)(3)(i) of 

this section minus the account’s share of 

the CSAPR NOX Ozone Season Group 3 

allowance bank ceiling target for the 

control period determined under 

paragraph (d)(3)(ii) of this section. The 

allowances will be deducted on a firstin, first-out basis in the order set forth 

in § 97.1024(c)(2)(i) and (ii). 


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(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. 

■ 80. Amend § 97.1030 by: 

■ a. Revising paragraph (b)(1); and 

■ b. In paragraph (b)(3), removing 

‘‘(b)(2)’’ and adding in its place ‘‘(b)(1) 

or (2)’’. 

The revision reads as follows: 

§ 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 

§ 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 

§ 52.38(b)(2)(iii)(B) of this chapter; 

(iii) [EFFECTIVE DATE OF FINAL 

RULE], for a unit in a State (and Indian 

country within the borders of such 

State) listed in § 52.38(b)(2)(iii)(C) of 

this chapter, where the unit is required 

to report NOX mass emissions data or 

NOX emissions rate data according to 40 

CFR part 75 to address other regulatory 

requirements; or 

(iv) [180 DAYS AFTER EFFECTIVE 

DATE OF FINAL RULE] for a unit in a 

State (and Indian country within the 

borders of such State) listed in 

§ 52.38(b)(2)(iii)(C) of this chapter, 

where the unit is not required to report 

NOX mass emissions data or NOX

emissions rate data according to 40 CFR 

part 75 to address other regulatory 

requirements. 

* * * * * 

■ 81. Amend § 97.1034 by: 

■ a. Revising paragraph (d)(2)(i); and 

■ 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: 

§ 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 § 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 

§ 52.38(b)(2)(iii)(B) of this chapter; or 

(C) The calendar quarter covering 

[EFFECTIVE DATE OF FINAL RULE] 

through June 30, 2023, for a unit in a 

State (and Indian country within the 

borders of such State) listed in 

§ 52.38(b)(2)(iii)(C) of this chapter; 

* * * * * 

[FR Doc. 2022–04551 Filed 3–30–22; 4:15 pm] 

BILLING CODE 6560–50–P 


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