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Proposed Rule

Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS

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Start Preamble Start Printed Page 68964

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

This proposed action is taken in response to the United States Court of Appeals for the District of Columbia Circuit's (D.C. Circuit) remand of the Cross-State Air Pollution Rule (CSAPR) Update in Wisconsin v. EPA on September 13, 2019. The CSAPR Update finalized Federal Implementation Plans (FIPs) for 22 states to address their interstate pollution-transport obligations under the Clean Air Act (CAA) for the 2008 ozone National Ambient Air Quality Standards (NAAQS). The D.C. Circuit found that the CSAPR Update, which was published on October 26, 2016, as a partial remedy to address upwind states' obligations prior to the 2018 Moderate area attainment date under the 2008 ozone NAAQS, was unlawful to the extent it allowed those states to continue their significant contributions to downwind ozone problems beyond the statutory dates by which downwind states must demonstrate their attainment of the air quality standards. On the same grounds, the D.C. Circuit also vacated the CSAPR Close-Out in New York v. EPA on October 1, 2019. This proposed rule, if finalized, will resolve 21 states' outstanding interstate ozone transport obligations with respect to the 2008 ozone NAAQS. The U.S. Environmental Protection Agency (EPA) is taking this action under the Clean Air Act section known as the “good neighbor provision.”

This action proposes to find that for 9 of the 21 states for which the CSAPR Update was found to be only a partial remedy (Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin), their projected nitrogen oxides (NOX) emissions in the 2021 ozone season and thereafter do not significantly contribute to a continuing downwind nonattainment and/or maintenance problem, and therefore the states' CSAPR Update FIPs (or the SIPs subsequently approved to replace certain states' CSAPR Update FIPs) fully address their interstate ozone transport obligations with respect to the 2008 ozone NAAQS. This action also proposes to find that for the 12 remaining states (Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia), their projected 2021 ozone season NOX emissions significantly contribute to downwind states' nonattainment and/or maintenance problems for the 2008 ozone NAAQS. EPA proposes to issue new or amended FIPs for these 12 states to replace their existing CSAPR NOX Ozone Season Group 2 emissions budgets for electricity generating units (EGUs) with revised budgets via a new CSAPR NOX Ozone Season Group 3 Trading Program. EPA is proposing to require implementation of the revised emission budgets beginning with the 2021 ozone season (which runs annually from May 1-September 30). Based on EPA's assessment of remaining air quality issues and additional emission control strategies for EGUs and other emissions sources in other industry sectors (non-EGUs), EPA further proposes that the proposed NOX emission reductions fully eliminate these states' significant contributions to downwind air quality problems for the 2008 ozone NAAQS. EPA also proposes in this action an error correction for its June 2018 approval of Kentucky's good neighbor SIP.

DATES:

Comments must be received on or before December 14, 2020.

Public Hearing: EPA will hold a virtual public hearing on November 12, 2020. Please refer to the SUPPLEMENTARY INFORMATION section for additional information on the public hearing.

ADDRESSES:

You may send comments, identified by Docket ID No. EPA-HQ-OAR-2020-0272, via the Federal eRulemaking Portal: https://www.regulations.gov/​. 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 closed to the public, with limited exceptions, to reduce the risk of transmitting COVID-19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https://www.regulations.gov/​ or email, as there may be a delay in processing mail and faxes. 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.

Throughout this proposal, EPA is soliciting comment on numerous aspects of the proposed rule. EPA has indexed each comment solicitation with an alpha-numeric identifier (e.g., “C-1”, “C-2”, “C-3”, . . .). Accordingly, we ask that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. We ask that commenters include the identifier in either a heading, or within the text of each comment (e.g., “In response to solicitation of comment C-1, . . .”) to make clear which comment solicitation is being addressed. We emphasize that we are not limiting comment to these identified areas and welcome comments on any matters that are within scope of this action.

EPA will announce further details on the virtual public hearing, as well as registration information, at https://www.epa.gov/​csapr/​revised-cross-state-air-pollution-update. Refer to the SUPPLEMENTARY INFORMATION section below for additional information.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Mr. Daniel Hooper, Clean Air Markets Division, Office of Atmospheric Programs (Mail Code 6204M), Environmental Protection Agency, 1200 Pennsylvania Avenue NW, Washington, DC 20460; telephone number: (202) 343-9167; email address: Hooper.Daniel@epa.gov.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

Preamble Glossary of Terms and Abbreviations

The following are abbreviations of terms used in the preamble.

4-Step Good Neighbor Framework 4-Step Framework

AEO Annual Energy Outlook

AQAT Air Quality Assessment Tool

AQM TSD Air Quality Modeling Technical Support Document

CAA or Act Clean Air Act

CAIR Clean Air Interstate Rule

CAMx Comprehensive Air Quality Model with Extensions

CBI Confidential Business Information

CEMS Continuous Emission Monitoring Systems

CFR Code of Federal Regulations

CMDb Control Measures DatabaseStart Printed Page 68965

CMV Commercial Marine Vehicle

CoST Control Strategy Tool

CRA Congressional Review Act

CSAPR Cross-State Air Pollution Rule

EGU Electric Generating Unit

EISA Energy Independence and Security Act

EPA U.S. Environmental Protection Agency

FIP Federal Implementation Plan

FR Federal Register

GWh Gigawatt-hour

IC Internal Combustion

ICI Industrial, Commercial, and Institutional

ICR Information Collection Request

IPM Integrated Planning Model

iSIP Infrastructure State Implementation Plan

km Kilometer

lb/mmBtu Pounds per Million British Thermal Units

LEC Low Emission Combustion

LNB Low-NOX Burners

MJO Multi-Jurisdictional Organizations

mmBtu Million British Thermal Units

MOVES Motor Vehicle Emission Simulator

MSAT2 Mobile Source Air Toxic Rule

NAAQS National Ambient Air Quality Standard

NEI National Emission Inventory

NESHAP National Emission Standards for Hazardous Air Pollutants

NOX Nitrogen Oxides

NODA Notice of Data Availability

Non-EGU Non-electric Generating Unit

NSPS New Source Performance Standard

NUSA New Unit Set-Aside

OSAT/APCA Ozone Source Apportionment Technology/Anthropogenic Precursor Culpability Analysis

OMB Office of Management and Budget

OTR Ozone Transport Region

PEMS Predictive Emissions Monitoring System

PM2.5 Fine Particulate Matter

ppb Parts Per Billion

RACT Reasonably Available Control Technology

RIA Regulatory Impact Analysis

RICE Reciprocating Internal Combustion Engines

RRF Relative Response Factor

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SMOKE Sparse Matrix Operator Kernel Emissions

SNCR Selective Non-catalytic Reduction

SO2 Sulfur Dioxide

TIP Tribal Implementation Plan

TSD Technical Support Document

tpy Ton Per Year

ULNB Ultra-low NOX Burner

VOC Volatile Organic Compound

WRF Weather Research and Forecasting Model

Table of Contents

I. Executive Summary

A. Purpose of Regulatory Action

B. Summary of the Major Provisions of the Regulatory Action

C. Benefits and Costs

II. Public Participation

A. Written Comments

B. Participation in Virtual Public Hearing

III. General Information

A. Does this action apply to me?

IV. EPA's Legal Authority for the Proposed Rule

A. Statutory Authority

B. Prior Good Neighbor Rulemakings Addressing Regional Ozone

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

A. The Interstate Ozone Transport Challenge

B. Relationship Between This Regulatory Action and the 2015 Ozone NAAQS

C. Proposed Approach To Address the Remanded Transport Obligations for the 2008 Ozone NAAQS

1. Events Affecting Application of the Good Neighbor Provision for the 2008 Ozone NAAQS

2. FIP Authority for Each State Covered by the Proposed Rule

3. The 4-Step Good Neighbor Framework

VI. Analyzing Downwind Air Quality and Upwind-State Contributions

A. Overview of Air Quality Modeling Platform

B. Emission Inventories

1. Foundation Emission Inventory Data Sets

2. Development of Emission Inventories for EGUs

3. Development of Emission Inventories for Non-EGU Point Sources

4. Development of Emission Inventories for Onroad Mobile Sources

5. Development of Emission Inventories for Commercial Marine Vessels

6. Development of Emission Inventories for Other Nonroad Mobile Sources

7. Development of Emission Inventories for Nonpoint Sources

C. Air Quality Modeling To Identify Nonattainment and Maintenance Receptors

D. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions

2. Application of Screening Threshold

VII. Quantifying Upwind-State NOX Reduction Potential To Reduce Interstate Ozone Transport for the 2008 NAAQS

A. The Multi-Factor Test

B. Identifying Levels of Control Stringency

1. EGU NOX Mitigation Strategies

2. Non-EGU NOX Mitigation Strategies

3. Mobile Source NOX Mitigation Strategies

C. Control Stringencies Represented by Cost Threshold ($ per ton) and Corresponding Emission Reductions

1. EGU Emission Reduction Potential by Cost Threshold

2. Non-EGU Emission Reduction Potential by Cost Threshold

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

1. EGU Assessment

2. Non-EGU Assessment

3. Overcontrol Analysis

VIII. Implementation of Emissions Reductions

A. Regulatory Requirements for EGUs

B. Quantifying State Emissions Budgets

C. Elements of Proposed Trading Program

1. Applicability

2. State Budgets, Variability Limits, Assurance Levels, and Penalties

3. Unit-Level Allocations of Emission Allowances

4. Transitioning From Existing CSAPR NOX Ozone-Season Group 2 Trading Program

5. Compliance Deadlines

6. Monitoring and Reporting

7. Recordation of Allowances

8. Proposed Conforming Revisions to Regulations for Existing Trading Programs

D. Submitting a SIP

1. SIP Option To Modify 2022 Allocations

2. SIP Option To Modify Allocations in 2023 and Beyond

3. SIP Revisions That Do Not Use the New Group 3 Trading Program

4. Submitting a SIP To Participate in the New Group 3 Trading Program for States Not Included

E. Title V Permitting

F. Relationship to Other Emission Trading and Ozone Transport Programs

1. Existing Trading Programs

2. Title IV Interactions

3. NOX SIP Call Interactions

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

A. Amended CSAPR Update FIP Provisions

B. New CSAPR NOX Ozone Season Group 3 Trading Program Provisions

C. Transitional Provisions

D. Conforming Revisions, Corrections, and Clarifications to Existing Regulations

XI. Statutory and Executive Order Reviews

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

B. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs

C. Paperwork Reduction Act (PRA)

D. Regulatory Flexibility Act (RFA)

E. Unfunded Mandates Reform Act (UMRA)

F. Executive Order 13132: Federalism

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

H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

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

J. National Technology Transfer and Advancement Act (NTTAA)

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

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

I. Executive Summary

The 2008 ozone National Ambient Air Quality Standards (NAAQS) is an 8-hour standard that was set at 75 parts Start Printed Page 68966per billion (ppb).[1] The U.S. Environmental Protection Agency (EPA) published the Cross-State Air Pollution Rule (CSAPR) Update on October 26, 2016, which partially addressed the interstate transport of emissions from 21 states with respect to the 2008 ozone NAAQS.[2] 81 FR 74504. On December 21, 2018, EPA published the CSAPR Close-Out, which found that the CSAPR Update was a complete remedy based on air quality analysis of the year 2023.[3]

On September 13, 2019, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) remanded the CSAPR Update, concluding that it was invalid in one respect because it unlawfully allowed upwind states to continue their significant contributions to downwind air quality problems beyond the statutory dates by which downwind States must demonstrate their attainment of ozone air quality standards. Wisconsin v. EPA, 938 F.3d 303, 318-20 (D.C. Cir. 2019) (Wisconsin) (per curiam); see also id. 336-37 (concluding that remand without vacatur was appropriate). Subsequently, on October 1, 2019, in a judgment order, the D.C. Circuit vacated the CSAPR Close-Out on the same grounds on which it had remanded without vacatur the CSAPR Update in Wisconsin. New York v. EPA, 781 Fed. App'x 4, 7 (D.C. Cir. 2019) (New York). The court found the CSAPR Close-Out inconsistent with the Wisconsin holding because the rule analyzed the year 2023 rather than 2021 (“the next applicable attainment date”) and failed to demonstrate that it was an impossibility to address significant contribution by the 2021 attainment date.

In this proposal to revise the CSAPR Update on remand, in compliance with Wisconsin and New York, EPA has aligned its analysis and the implementation of emission reductions required to address significant contribution with the 2021 ozone season, which corresponds to the July 20, 2021, Serious area attainment date for the 2008 ozone NAAQS. EPA has further determined which emission reductions are impossible to achieve by the 2021 attainment date and whether any such additional emission reductions should be required beyond that date, see Wisconsin, 938 F.3d at 320; New York, 781 Fed. App'x at 7.

Unless explicitly raised in this proposal, EPA is not reopening any determinations, findings, or statutory or regulatory interpretations that are not required to address the Wisconsin remand. This proposed action addressing the remand of the CSAPR Update in Wisconsin will also have the effect of addressing the outstanding obligations that resulted from the D.C. Circuit's vacatur of the CSAPR Close-Out in New York. See New York, 781 Fed. App'x at 7.

A. Purpose of the Regulatory Action

The purpose of this rulemaking is to protect public health and welfare by reducing interstate transport of certain emissions that significantly contribute to nonattainment, or interfere with maintenance, of the 2008 ozone NAAQS in the U.S. Ground-level 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. Ozone exposure can also negatively impact ecosystems, for example, by limiting tree growth. Studies have established that ozone transport occurs on a regional scale (i.e., hundreds of miles) over much of the eastern U.S., with elevated concentrations occurring in rural as well as metropolitan areas.[4 5] As discussed in more detail in Section V.A.1, assessments of ozone control approaches have concluded that nitrogen oxides (NOX) control strategies are effective to reduce regional-scale ozone transport.[6]

Clean Air Act (CAA or the Act) section 110(a)(2)(D)(i)(I), which is also known as the “good neighbor provision,” 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] The statute vests states with the primary responsibility to address interstate emission transport through the development of good neighbor State Implementation Plans (SIPs), which are one component of larger SIP submittals typically required three years after EPA promulgates a new or revised NAAQS. These larger SIPs are often referred to as “infrastructure” SIPs or iSIPs. See CAA section 110(a)(1) and (2). EPA supports state efforts to submit good neighbor SIPs for the 2008 ozone NAAQS and has shared information with states to facilitate such SIP submittals. However, the CAA also requires EPA to fill a backstop role by issuing Federal Implementation Plans (FIPs) where states fail to submit good neighbor SIPs or EPA disapproves a submitted good neighbor SIP. See generally CAA section 110(k) and 110(c).

On October 26, 2016, EPA published the CSAPR Update, which finalized FIPs for 22 states that EPA found failed to submit a complete good neighbor SIP (15 states) [8] or for which EPA issued a final rule disapproving their good neighbor SIP (7 states).[9] The FIPs promulgated for these states included new electric generating units (EGUs) NOX ozone season emission budgets to reduce interstate transport for the 2008 ozone NAAQS. These emission budgets took effect in 2017 in order to assist downwind states with attainment of the 2008 ozone NAAQS by the 2018 Moderate area attainment date. EPA acknowledged at the time that the FIPs promulgated for 21 of the 22 states only partially addressed good neighbor obligations under the 2008 ozone NAAQS.[10] The 22 states for which EPA promulgated FIPs to reduce interstate ozone transport as to the 2008 ozone NAAQS are listed in Table I.A-1.

Table I.A—1 List of 22 Covered States for the 2008 8-Hour Ozone NAAQS in the CSAPR   Update

State
Alabama
Arkansas
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
New Jersey
Start Printed Page 68967
New York
Ohio
Oklahoma
Pennsylvania
Tennessee
Texas
Virginia
West Virginia
Wisconsin

In response to the D.C. Circuit's remand of the CSAPR Update in Wisconsin v. EPA and the court's vacatur of the CSAPR Close-Out in New York v. EPA, this rule proposes to find that 12 of the 22 states listed in Table I.A-1 require further ozone season NOX emission reductions to address the good neighbor provision as to the 2008 ozone NAAQS. As such, EPA proposes to promulgate new or revised FIPs for these states that include new EGU NOX ozone season emission budgets, with implementation of these emission budgets beginning with the 2021 ozone season.[11] The 12 states for which EPA is proposing to promulgate new or revised FIPs to reduce interstate ozone transport as to the 2008 ozone NAAQS in this rulemaking are listed in Table I.A-2.

Table I.A—2 Proposed List of 12 Covered States for the 2008  8-Hour Ozone NAAQS

State
Illinois
Indiana
Kentucky
Louisiana
Maryland
Michigan
New Jersey
New York
Ohio
Pennsylvania
Virginia
West Virginia

EPA also proposes to adjust these states' emission budgets for each ozone season thereafter to incentivize ongoing operation of identified emission controls to address significant contribution, until such time that our air quality projections demonstrate resolution of the downwind nonattainment and/or maintenance problems for the 2008 ozone NAAQS. No further budget adjustments would be made after that time (i.e., after the 2024 ozone season in EPA's proposed analysis). EPA proposes to implement the new state-level ozone season emission budgets through a new CSAPR NOX Ozone Season Group 3 Trading Program. Based on EPA's assessment of remaining air quality issues and additional emission control strategies, EPA further proposes to find that these NOX emission reductions fully eliminate these states' significant contributions to downwind air quality problems for the 2008 ozone NAAQS.

As discussed in more detail in Section V.C.2.b below, for one state, Kentucky, EPA is proposing to make an error correction under CAA section 110(k)(6) of its June 2018 approval of that state's SIP, which had concluded that the CSAPR Update was a complete remedy based on modeling of the 2023 analytic year. EPA proposes to determine that the basis for that conclusion has been invalidated by the decisions in Wisconsin and New York, and that Kentucky's good neighbor obligations are outstanding. In light of the Wisconsin remand of Kentucky's FIP and our proposed error correction, EPA has the necessary authority to amend the CSAPR Update FIP for Kentucky.

For the nine remaining states with FIPs promulgated under the CSAPR Update that EPA previously found partially addressed good neighbor obligations for the 2008 ozone NAAQS (Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin), EPA's updated air quality and contributions analysis shows that these states are not linked to any downwind air quality problems in 2021.[12] Therefore, EPA proposes to find that the existing CSAPR Update FIPs (or the SIP revisions later approved to replace the CSAPR Update FIPs) for these states satisfy their good neighbor obligations for the 2008 ozone NAAQS.[13] Consequently, EPA is not proposing to require additional emission reductions from sources in these states in this proposed rulemaking.

B. Summary of the Major Provisions of the Regulatory Action

To reduce interstate ozone transport under the authority provided in CAA section 110(a)(2)(D)(i)(I), this rule proposes to further limit ozone season (May 1 through September 30) NOX emissions from EGUs in 12 states using the same framework used by EPA in developing the CSAPR and other good neighbor rules (the 4-step good neighbor framework or 4-step framework). The 4-step good neighbor framework provides a process to address the requirements of the good neighbor provision for ground-level ozone NAAQS: (1) Identifying downwind receptors that are expected to have problems attaining or 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., here, a 1 percent contribution threshold); (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 downwind, implementing the necessary emissions reductions through enforceable measures. In this proposed rule, EPA applies this 4-step framework to respond to the D.C. Circuit's remand and to revise the CSAPR Update with respect to the 2008 ozone NAAQS.

In order to apply the first step of the 4-step framework to the 2008 ozone NAAQS, EPA performed air quality modeling coupled with ambient measurements in an interpolation technique to project ozone concentrations at air quality monitoring sites in 2021.[14] EPA evaluated 2021 projected ozone concentrations 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 2008 ozone NAAQS.

Start Printed Page 68968

To apply the second step of the framework, EPA used air quality modeling and an interpolation technique to quantify the contributions from upwind states to ozone concentrations in 2021 at downwind receptors. Once quantified, EPA then evaluated these contributions relative to a screening threshold of 1 percent of the NAAQS (i.e., 0.75 ppb). States with contributions that equal or exceed 1 percent of the NAAQS were identified as warranting further analysis for significant contribution to nonattainment or interference with maintenance. States with contributions below 1 percent of the NAAQS were considered to not significantly contribute to nonattainment or interfere with maintenance of the NAAQS in downwind states. Based on EPA's updated air quality and contribution analysis using 2021 as the analytic year, EPA proposes that the following 12 states have contributions that equal or exceed 1 percent of the 2008 ozone NAAQS, and thereby warrant further analysis for significant contribution to nonattainment or interference with maintenance: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.

At the third step of the 4-step framework, EPA applied the multi-factor test used in the CSAPR Update, which evaluates cost, available emission reductions, and downwind air quality impacts to determine the amount of linked upwind states' emissions that “significantly” contribute to downwind nonattainment or maintenance receptors. In this action, EPA applies the multifactor test to both EGU and non-EGU source categories and assesses potential emission reductions in all years for which there is a potential remaining interstate ozone transport problem (i.e., through 2025), in order to ensure a full remedy in compliance with the Wisconsin decision.

EPA identified a control strategy that reflects the optimization of existing selective catalytic reduction (SCR) controls and installation of state-of-the-art NOX combustion controls at EGUs, with an estimated marginal cost of $1,600 per ton. It is at this control stringency where incremental EGU NOX reduction potential and corresponding downwind ozone air quality improvements are maximized. That is, the ratio of emission reductions to marginal cost and the ratio of ozone improvements to marginal cost are maximized relative to the other control stringency levels evaluated. EPA finds that these very cost-effective EGU NOX reductions will make meaningful and timely improvements in downwind ozone air quality to address interstate ozone transport for the 2008 ozone NAAQS, as discussed in section VII.D.1 below. Further, this evaluation shows that emission budgets reflecting the $1,600 per ton cost threshold do not over-control upwind states' emissions relative to either the downwind air quality problems to which they are linked at step 1 or the 1 percent contribution threshold that triggers further evaluation at step 2 of the 4-step framework.

EPA notes that these proposed EGU control strategies (optimization of existing SCR controls and installation of state-of-the-art NOX combustion controls) were the same strategies selected in the CSAPR Update for the 2017 ozone season, and which at that time EPA characterized as only a partial remedy. For this rule, EPA extends its evaluation of the reduction potential from these control strategies to years beyond 2017 in order to assess a full remedy. EPA's updated analysis, as discussed in more detail in Section VII, leads the Agency to propose that these control strategies can provide additional cost-effective emission reductions for the 2021 through 2024 ozone seasons. While EPA's analysis indicates that the majority of EGUs implemented these control strategies in response to the CSAPR Update, changes in the power sector since the 2017 ozone season and updated air quality and contribution analysis show that there is a demonstrated need to update the emission budgets for these 12 states to fully eliminate significant contribution.

For non-EGU industry sectors and emissions sources, EPA applied the step 3 multi-factor test to determine whether any emissions reductions should be required from non-EGU sources to address significant contribution under the 2008 ozone NAAQS. EPA acknowledges that its current datasets with information on emissions, existing controls on emissions sources, emission-reduction potential, and air quality impacts for these sources are relatively incomplete and uncertain compared to the datasets it has for EGUs. Nonetheless, using the best information currently available to the Agency, the proposed analysis suggests that there are relatively fewer emissions reductions available at a cost threshold comparable to the cost threshold selected for EGUs. Such reductions are estimated to have a relatively small effect on any downwind receptor in the year by which such controls could likely be installed. For these reasons, EPA proposes that limits on ozone season NOX emissions from non-EGU sources are not required to eliminate “significant” contribution under the 2008 ozone NAAQS (see section VII.D.2).

To improve the underlying data and assessment of emission reduction potential from non-EGU sources for this and future regulatory efforts, EPA is soliciting comment on the assessment of emission reduction potential from the glass and cement manufacturing sectors discussed in Sections VII.B.2, VII.C.2, and VII.D.2. In addition, EPA summarizes the available information on all potential control measures for non-EGU emissions sources or units with 150 tons per year or more of pre-control NOX emissions in several industry sectors for the 12 states in Table I.A-2. This information illustrates that there are many potential approaches to assessing emissions reductions from non-EGU emissions sources or units. EPA is soliciting comment on the completeness and accuracy of this additional information on potential control measures for non-EGU emissions sources or units in several industry sectors. Specifically, EPA summarized information on the application, costs, and installation timing of ultra-low NOX burners on industrial, commercial, and institutional (ICI) boilers and low emission combustion on reciprocating internal combustion (IC) engines.

Based on EPA's analysis at step 3, the Agency proposes EGU NOX ozone season emission budgets developed using uniform control stringency represented by $1,600 per ton. EPA proposes to determine that with implementation of this control strategy, the 12 states in Table I.A-2 will have fully addressed significant contribution under the good neighbor provision for the 2008 ozone NAAQS. EPA is proposing to align implementation of emission budgets with relevant attainment dates for the 2008 ozone NAAQS, as required by the D.C. Circuit's decision in Wisconsin v. EPA.[15] As EPA's final 2008 Ozone NAAQS SIP Requirements Rule [16] established the attainment deadline of July 20, 2021, for ozone nonattainment Start Printed Page 68969areas currently designated as Serious, EPA proposes to establish emission budgets and implementation of these emission budgets starting with the 2021 ozone season as shown in Table I.B-1.

Table I.B—1 Proposed EGU NOX Ozone Season Emission Budgets Emissions

[Ozone season NOX tons] *

State2021 Budget2022 Budget2023 Budget2024 Budget
Illinois9,4449,4158,3978,397
Indiana12,50011,99811,9989,447
Kentucky14,38411,93611,93611,936
Louisiana15,40214,87114,87114,871
Maryland1,5221,4981,4981,498
Michigan12,72711,7679,8039,614
New Jersey1,2531,2531,2531,253
New York3,1373,1373,1373,119
Ohio9,6059,6769,6769,676
Pennsylvania8,0768,0768,0768,076
Virginia4,5443,6563,6563,395
West Virginia13,68612,81311,81011,810
Total106,280100,09696,11193,092
* Note—the 2022 and beyond budgets incorporate the installation of state-of-the-art NOX combustion controls; whereas the 2021 budgets do not. Additionally, the 2024 emissions budget applies to 2024 and each year thereafter.

As noted in Section I, EPA further determined which emission reductions are impossible to achieve by the 2021 attainment date—and whether any such additional emission reductions should be required beyond that date.[17] See Wisconsin, 938 F.3d at 320. EPA estimates that one part of the selected control strategy—installation of state-of-the-art NOX combustion controls—can occur between approximately one to six months at any particular unit. As the final rule will likely become effective either immediately prior to or slightly after the start of the 2021 ozone season, EPA determined it is not possible to install state-of-the-art NOX combustion controls on a regional scale by the beginning of the 2021 ozone season.[18] EPA proposes to conclude that an emission reduction strategy is impossible if it cannot be implemented statewide by the relevant attainment date because statewide budgets are based on fleetwide averages. Therefore, the proposed 2021 ozone season emission budgets reflect only the control strategy of optimizing existing SCR controls at the affected EGUs, but the proposed emission budgets for the 2022 ozone season and beyond reflect both the continued optimization of existing SCR controls and installation of state-of-the-art NOX combustion controls. Detailed installation-timing information for this technology is available in Section VII.B and the EGU NOX Mitigation Strategies TSD.

As discussed in section VII.D.1, EPA's air quality projections anticipate that with the implementation of the identified control stringency for EGUs represented by $1,600 per ton, downwind nonattainment and maintenance problems for the 2008 ozone NAAQS will persist through the 2024 ozone season. Therefore, EPA is proposing to adjust emission budgets for upwind states that remain linked to downwind nonattainment and maintenance problems through the 2024 ozone season to incentivize the continued optimization of existing SCR controls and installation of state-of-the-art NOX combustion controls. The 2024 emission budgets would then continue to apply in each year thereafter.

As discussed below, EPA notes that emissions budgets are implemented through the market-based mechanism of a trading program for emission allowances. Under such a trading program, sources have the compliance flexibility to make emissions reductions themselves or to purchase allowances from other sources (either directly from those sources or indirectly through a third party) that do not need those allowances to cover their remaining emissions. Given this compliance flexibility, EPA is taking comment on whether delaying the incorporation of emission reduction potential from the installation of state-of-the-art NOX combustion controls into state emission budgets until 2022 is necessary (Comment C-1).

To apply the fourth step of the 4-step framework (i.e., implementation), EPA proposes to include enforceable measures in the promulgated FIPs to achieve the required emission reductions in each of the 12 states. Specifically, the FIPs would require power plants in the 12 states to participate in a new CSAPR NOX Ozone Season Group 3 Trading Program that largely replicates the existing CSAPR NOX Ozone Season Group 2 Trading Program; with the main differences being the geography and budget stringency. Aside from the removal of the 12 covered states from the current CSAPR NOX Ozone Season Group 2 Trading Program, this proposal leaves unchanged the budget stringency and geography of the existing CSAPR NOX Ozone Season Group 1 and Group 2 trading programs.

For this rulemaking, EPA is proposing to authorize a one-time conversion of allowances banked in 2017-2020 under the CSAPR Update NOX Ozone Season Group 2 Trading Program into a limited number of allowances that can be used for compliance in the CSAPR NOX Ozone Season Group 3 Trading Program. Similar to the approach taken in the CSAPR Update, EPA is proposing to base the conversion on a formula that ensures emissions in the CSAPR NOX Ozone Season Group 3 Trading Program region do not exceed a specified level (defined as emissions up to the sum of Start Printed Page 68970the states' ozone season emissions budgets and variability limits) as a result of the use of banked allowances from the Group 2 trading program. EPA also proposes to provide a process through which holders of Group 2 allowances in non-facility accounts (“general” accountholders) could designate any Group 2 allowances that they do not wish to have converted to Group 3 allowances.

The remainder of this preamble is organized as follows: Section IV describes EPA's legal authority for this proposed action; section V describes the human health and environmental context, as well as EPA's proposed approach for addressing interstate transport for the 2008 ozone NAAQS; section VI describes its assessment of downwind receptors of concern and upwind state ozone contributions to those receptors, including the air quality modeling platform and emission inventories that EPA used; section VII describes EPA's approach to quantify upwind state obligations in the form of final EGU NOX emission budgets; section VIII details the implementation requirements including key elements of the CSAPR trading program and deadlines for compliance; section IX describes the expected costs, benefits, and other impacts of this proposed rule; section X discusses changes to the existing regulatory text; and section XI discusses the statutes 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 compliance costs, climate benefits, and net benefits of the proposed rule, in 2016 dollars, discounted to 2021. The estimated net benefits are the estimated benefits minus the estimated costs of the proposed rule. The table represents the present value of non-monetized benefits from ozone, PM2.5 and NO2 reductions as a β, while b represents the equivalent annualized value of these non-monetized benefits. These values will differ across the discount rates and depend on the B's in Tables IX.4 and IX.5 presented in Section IX.

Table I.C—1 Estimated Compliance Costs, Climate Benfits and Net Benefits of the Proposed Rule, 2021 Through 2025

[Millions 2016$, discounted to 2021]

3% Discount rate7% Discount rate
Present Value:
Benefits cd101+β15+β
Climate Benefits c10115
Compliance Costs e8783
Net Benefits14+β−68+β
Equivalent Annualized Value:
Benefits22+b4+b
Climate Benefits224
Compliance Costs1920
Net Benefits3+b−17+b
a All estimates in this table are rounded to two significant figures, so numbers may not sum due to independent rounding.
b The annualized present value of costs and benefits are calculated over a 5 year period from 2021 to 2025.
c Benefits ranges represent discounting of climate benefits at a real discount rate of 3 percent and 7 percent. Climate benefits are based on changes (reductions) in CO2 emissions.
d β and b is the sum of all unquantified ozone, PM2.5, and NO2 benefits. The annual values of β and b will differ across discount rates. While EPA did not estimate these benefits in the RIA, Appendix 5B in the RIA presents PM2.5 and ozone estimates quantified using methods consistent with the previously published ISAs 1920 to provide information regarding the potential magnitude of the benefits of this proposed rule.
e The costs presented in this table reflect annualized present value compliance costs calculated over a 5 year period from 2021 to 2025.

Table 1.C-1 does not include quantified and monetized health benefits associated with reduced exposures to concentrations of ground-level ozone and fine particulates. The Agency intends to update its approach for quantifying the benefits of air quality changes by considering the evidence reported in recently completed Integrated Science Assessments for ground-level ozone and fine particulates and accounting for forthcoming recommendations from the Science Advisory Board on this issue. This process is still underway and will not be completed in time for this proposed rule. See Section IX of this preamble for more discussion. However, to provide perspective regarding the scope of the estimated benefits, Appendix 5B of the RIA illustrates the potential health effects associated with the changes in PM2.5 and ozone concentrations as calculated using methods developed prior to the 2019 p.m. ISA and 2020 Ozone ISA. That analysis provides perspective regarding the scope of the estimated benefits. EPA is in the process of recalibrating its benefits estimates for all PM and ozone health endpoints. EPA intends to update its quantitative methods for estimating the number and economic value of PM2.5 and ozone health effects in time for publication as part of the final rule.

As shown in Table I.C-1, the PV of the climate benefits of this proposed rule, discounted at a 7-percent rate, is estimated to be about $15 million, with an EAV of about $4 million. At a 3-percent discount rate, the PV of the climate benefits is estimated to be about $101 million, with an EAV of $22 million. The PV of the compliance costs, discounted at a 7-percent rate, is estimated to be about $83 million, with an EAV of about $20 million. At a 3-percent discount rate, the PV of the compliance costs is estimated to be about $87 million, with an EAV of about Start Printed Page 68971$19 million. The PV of the net benefits of this proposed rule, discounted at a 7-percent rate, is estimated to be about −$68 million, with an EAV of about −$17 million. At a 3-percent discount rate, the PV of the net benefits is estimated to be about $14 million, with an EAV of about $3 million .

II. Public Participation

A. Written Comments

Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2020-0272, at https://www.regulations.gov. Once submitted, comments cannot be edited or removed from the docket. 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. 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.

EPA is temporarily suspending its Docket Center and Reading Room for public visitors to reduce the risk of transmitting COVID-19. Written comments submitted by mail are temporarily suspended and no hand deliveries will be accepted. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https://www.regulations.gov. For further information and updates on EPA Docket Center services, please visit us online at https://www.epa.gov/​dockets.

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. Participation in Virtual Public Hearing

Please note that EPA is deviating from its typical approach because the President has declared a national emergency. Because of current CDC recommendations, as well as state and local orders for social distancing to limit the spread of COVID-19, EPA cannot hold in-person public meetings at this time.

EPA will begin pre-registering speakers for the hearing upon publication of this document in the Federal Register. To register to speak at the virtual hearing, please use the online registration form available at https://www.epa.gov/​csapr/​revised-cross-state-air-pollution-update or contact Ms. Kimberly Liu at liu.kimberly@epa.gov or 202-564-6586 to register to speak at the virtual hearing. The last day to pre-register to speak at the hearing will be November 6, 2020. On November 10, 2020, EPA will post a general agenda for the hearing that will list pre-registered speakers in approximate order at: https://www.epa.gov/​csapr/​revised-cross-state-air-pollution-update.

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. EPA encourages commenters to provide EPA with a copy of their oral testimony electronically (via email) by emailing it to Ms. Kimberly Liu at liu.kimberly@epa.gov. EPA also recommends submitting the text of your oral comments as written comments to the rulemaking docket.

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/​revised-cross-state-air-pollution-update. While EPA expects the hearing to go forward as set forth above, please monitor our website or contact Ms. Kimberly Liu at liu.kimberly@epa.gov or 202-564-6586 to determine if there are any updates. EPA does not intend to publish a document in the Federal Register announcing updates.

If you require the services of a translator or special accommodations such as audio description, please pre-register for the hearing with Kimberly Liu at liu.kimberly@epa.gov or 202-564-6586 and describe your needs by November 5, 2020. 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 EGUs, and regulates the groups identified in Table III.A-1:

Table III.A-1—Regulated Groups

Industry groupNAICS *
Fossil fuel-fired electric power generation221112
* North American Industry Classification System.

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be regulated by this action. Other types of entities not listed in the table could also be regulated. For example, as discussed in Section VII.D.2 below, EPA is requesting comment on potential control strategies for emissions sources and industry sectors outside of the fossil fuel-fired power sector. Some of these industry sectors include cement, glass, chemical, and paper manufacturing, pipeline transportation, and oil and gas extraction. To determine whether your EGU entity is proposed to be regulated by this action, you should carefully examine the applicability criteria found in 40 CFR 97.804, which EPA is not proposing to alter in this action. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section.

IV. EPA's Legal Authority for the Proposed Rule

A. Statutory Authority

The statutory authority for this final action 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 action. 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 Start Printed Page 68972enforcement” of such NAAQS.[21] The statute directly imposes on states the duty to make these SIP submissions, and the requirement to make the submissions is not conditioned upon EPA taking any action other than promulgating a new or revised NAAQS.[22]

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.[23] It includes a list of specific elements that “[e]ach such plan” submission must address.[24]

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.[25]

CAA section 110(a)(2)(D)(i)(I), also known as the “good neighbor provision,” provides the primary basis for this proposal.[26] 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].” [27] EPA often refers to the emission reduction requirements under this provision as “good neighbor obligations” and submissions addressing these requirements as “good neighbor SIPs.”

Once EPA promulgates a NAAQS, EPA must designate areas as being in “attainment” or “nonattainment” of the NAAQS, or “unclassifiable.” CAA section 107(d).[28] 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 and additional control requirements. See CAA sections 181, 182.[29] 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.[30] 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).[31]

Section 301(a)(1) of the CAA also gives the Administrator the general authority to prescribe such regulations as are necessary to carry out functions under the Act.[32] 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. In this proposal, among other things, EPA is clarifying the applicability of CAA section 110(a)(2)(D)(i)(I) with respect to the 2008 ozone NAAQS. In particular, EPA is using its authority under CAA sections 110 and 301 to issue new or amended FIPs to revise NOX ozone season emission budgets for 12 states to eliminate their significant contribution to nonattainment or interference with maintenance of the 2008 ozone NAAQS in another state, and EPA is making findings as to 9 additional states that the CSAPR Update FIPs (or SIP revisions later approved to replace those FIPs) are a complete remedy and need no further revision.[33] In addition, EPA is obligated to respond to the D.C. Circuit's remand of the CSAPR Update in Wisconsin v. EPA, 938 F.3d 303, with respect to the 21 states for which the FIPs created by that rule were found to be only a partial remedy. This proposal, if finalized, will wholly resolve the Agency's obligations on remand. Finally, CAA section 301[34] 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, 78, and 97, as discussed in Section VIII of this preamble.

B. Prior Good Neighbor Rulemakings Addressing Regional Ozone

EPA has issued several rules interpreting and clarifying the requirements of CAA section 110(a)(2)(D)(i)(I) with respect to the regional transport of ozone for states in the eastern United States. 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.[35] 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. EPA set ozone season NOX budgets for each state, and the states were given the option to participate in a regional trading program, known as the NOX Budget Trading Program.[36] The D.C. Circuit largely upheld the NOX SIP Call in Michigan v. EPA, 213 F.3d 663 (DC 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.[37] CAIR required SIP revisions in 28 states and the District of Columbia to reduce emissions of sulfur dioxide (SO2) and/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 EPA promulgated the Start Printed Page 68973final CAIR in 2005, 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.[38] On March 15, 2006, EPA promulgated FIPs to implement the emission reductions required by CAIR.[39] 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.[40]

In 2011, EPA promulgated the CSAPR to address the issues raised by the remand of CAIR. The CSAPR addressed the two NAAQS at issue in CAIR and additionally addressed the good neighbor provision for the 2006 PM2.5 NAAQS.[41] The CSAPR required 28 states to reduce SO2 emissions, annual NOX emissions, and/or ozone season NOX emissions that significantly contribute to other states' nonattainment or interfere with other states' abilities to maintain these air quality standards.[42] To align implementation with the applicable attainment deadlines, EPA promulgated FIPs for each of the 28 states covered by the CSAPR. The FIPs require EGUs in the covered states to participate in regional trading programs to achieve the necessary emission 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.

The CSAPR was the subject of an adverse decision by the D.C. Circuit in August 2012.[43] 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 the 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 the 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.[44]

In 2016, EPA promulgated the CSAPR Update to address interstate transport of ozone pollution with respect to the 2008 ozone NAAQS.[45] The final rule generally updated the CSAPR ozone season NOX emissions budgets for 22 states to achieve cost-effective and immediately feasible NOX emission reductions from EGUs within those states.[46] 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.[47] 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 the CSAPR, each state can submit a good neighbor SIP at any time that, if approved by 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. Further details regarding the CSAPR Update are discussed in Sections V.C.1.a-b below.

In December 2018, EPA promulgated the CSAPR “Close-Out,” which determined that no further enforceable reductions in emissions of NOX were required with respect to the 2008 ozone NAAQS for 20 of the 22 eastern states covered by the CSAPR Update, and reflected that determination in revisions to the existing state-specific sections of the CSAPR Update regulations for those states.[48] Further details on the CSAPR Close-Out are discussed in Section V.C.1.c below.

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). As discussed in greater detail in Section V.C.1.d below, in September 2019, the D.C. Circuit upheld the CSAPR Update in virtually all respects, but remanded the rule because it was partial in nature and did not fully eliminate upwind states' significant contribution to nonattainment or interference with maintenance of the 2008 ozone NAAQS by “the relevant downwind attainment deadlines” in the CAA. Wisconsin, 938 F.3d at 313-15. In October 2019, the D.C. Circuit vacated the CSAPR Close-Out on the same grounds that it remanded the CSAPR Update in Wisconsin, specifically that the Close-Out rule did not analyze “the next applicable attainment date” of downwind states. New York, 781 Fed. App'x at 7.

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

A. The Interstate Ozone Transport Challenge

Interstate transport of NOX emissions poses significant challenges with respect to the 2008 ozone NAAQS in the eastern U.S. and thus presents a threat to public health and welfare.

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 (VOC) in Start Printed Page 68974the 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 VOC.

Because ground-level ozone formation increases with temperature and sunlight, ozone levels are generally higher during the summer. Increased temperature also increases emissions of volatile man-made and biogenic organics and can indirectly increase NOX emissions as well (e.g., increased electricity generation for air conditioning).

The 2008 primary and secondary ozone standards are both 75 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 75 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.

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 eastern U.S.[51] While substantial progress has been made in reducing ozone in many areas, interstate ozone transport is still an important component of peak ozone concentrations during the summer ozone season.

EPA has previously concluded in the NOX SIP Call, CAIR, and the CSAPR that, for reducing regional-scale ozone transport, a NOX control strategy would be most effective. NOX emissions can be transported downwind as NOX or, after transformation in the atmosphere, as ozone. As a result of ozone transport, in any given location, ozone pollution levels are impacted by a combination of local emissions and emissions from upwind sources. The transport of ozone pollution across state borders compounds the difficulty for downwind states in meeting health-based air quality standards (i.e., NAAQS). Assessments of ozone, for example those conducted for the October 2015 Regulatory Impact Analysis of the Final Revisions to the National Ambient Air Quality Standards for Ground-Level Ozone (EPA-452/R-15-007), continue to show the importance of NOX emissions for ozone transport. This analysis is in the docket for this proposal and can be also found at EPA's website at: https://www.epa.gov/​ttnecas1/​docs/​20151001ria.pdf.

Further, studies have found that EGU NOX emission 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 both ozone and dry-NO3 concentrations during the ozone season. Further, this study indicates that EGU emissions, which are generally released higher in the air column through tall stacks and are significant in quantity, may disproportionately contribute to long-range transport of ozone pollution on a per-ton basis.[52]

Previous regional ozone transport efforts, including the NOX SIP Call, CAIR, and the CSAPR, required ozone season NOX reductions from EGUs to address interstate transport of ozone. EPA took comment on regulating EGU NOX emissions to address interstate ozone transport in the notice-and-comment process for these rulemakings. EPA received no significant adverse comments in any of these proposals regarding the rules' focus on ozone season EGU NOX reductions to address interstate ozone transport.

As described in Section VII, EPA's analysis finds that the power sector continues to be capable of making NOX reductions at reasonable cost that reduce interstate transport with respect to ground-level ozone. EGU NOX emission reductions can be made in the near-term under this proposal by fully operating existing EGU NOX post-combustion controls (i.e., Selective Catalytic Reduction)—including optimizing NOX removal by existing operational controls and turning on and optimizing existing idled controls; installation of (or upgrading to) state-of-the-art NOX combustion controls; and shifting generation to units with lower NOX emission rates. Further, additional assessment reveals that these available EGU NOX reductions would make meaningful and timely improvements in ozone air quality.

EPA also observes that significant emissions reduction potential from EGUs is available through the post-combustion control retrofit strategies. These controls reduce emissions and can have a meaningful air quality impact, but, in contrast to the controls discussed above, they are not available in the near-term, and are only available on a longer time frame (reflecting the time required to develop, construct, and install the technology) and are estimated to have a higher cost.

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 November 2014 Regulatory Impact Analysis of the Proposed Revisions to the National Ambient Air Quality Standards for Ground-Level Ozone (EPA-452/P-14-006), in the docket for this proposal and available on EPA's website at: http://www.epa.gov/​ttn/​ecas/​regdata/​RIAs/​20141125ria.pdf, for more information on the human health and welfare and ecosystem effects associated with ambient ozone exposure.

B. Relationship Between This Regulatory Action and the 2015 Ozone NAAQS

On October 1, 2015, EPA strengthened the ground-level ozone NAAQS to 70 ppb on an eight-hour averaging time, based on extensive scientific evidence about ozone's effects on public health and welfare.[53] While reductions achieved by this rule may have the effect of aiding in attainment and maintenance of the 2015 standard, this action is taken solely with respect to EPA's authority to address remaining CAA good neighbor obligations under the 2008 ozone NAAQS. EPA and states are working outside of this proposed action to address the CAA good Start Printed Page 68975neighbor provision for the 2015 ozone NAAQS.

C. Proposed Approach To Address the Remanded Transport Obligations for the 2008 Ozone NAAQS

1. Events Affecting Application of the Good Neighbor Provision for the 2008 Ozone NAAQS

EPA is taking this action to address the remand of the CSAPR Update in Wisconsin v. EPA, 938 F.3d 303 (D.C. Cir. 2019). This Section will discuss the key, relevant aspects of the CSAPR Update, the related CSAPR Close-Out, and the D.C. Circuit's decisions in Wisconsin and New York v. EPA, 781 Fed. App'x 4 (D.C. Cir. 2019) (the latter of which vacated the Close-out Rule based on the same reasoning as the Wisconsin decision remanding the Update). The basis for EPA's authority under CAA section 110(c) (42 U.S.C. 7410(c)) to promulgate good neighbor FIPs for the 21 states subject to this action on remand is discussed in Sections IV and V.C.2.

a. The CSAPR Update

On October 26, 2016, the CSAPR Update was published in the Federal Register. 81 FR 74504. The purpose of the CSAPR Update was to address the good neighbor provision for the 2008 ozone NAAQS, as well as address remanded CSAPR obligations for the 1997 ozone NAAQS. The CSAPR Update required EGUs in 22 states to reduce ozone season NOX emissions that significantly contribute to other states' nonattainment or interfere with other states' abilities to maintain the 2008 ozone NAAQS.

To establish and implement the CSAPR Update emissions budgets, EPA followed the same four-step analytic process that it used in the CSAPR, an approach which reflects the evolution of the Agency's prior regional interstate transport rulemakings related to ozone NAAQS. The 4-step framework is described in more detail in Sections V.C.3 and VII.A.

In the CSAPR Update, to evaluate the scope of the interstate ozone transport problem at Step 1, EPA identified downwind areas that were expected to have problems attaining and maintaining the 2008 ozone NAAQS using modeling that projected air quality to a future compliance year. 81 FR 74517. EPA aligned the analysis and implementation of the CSAPR Update with the 2017 ozone season (May 1-September 30) in order to assist downwind states with attainment of the 2008 ozone NAAQS by the 2018 Moderate area attainment date. Id. at 74516. (EPA's final 2008 Ozone NAAQS SIP Requirements Rule established the attainment deadline of July 20, 2018, for ozone nonattainment areas classified as Moderate.[54] ) Because the attainment date fell during the 2018 ozone season, the 2017 ozone season was the last full season from which data could be used to determine attainment of the NAAQS by that date.

At Step 2, EPA identified upwind states that collectively contribute to these identified downwind areas. In the CSAPR Update, EPA used a screening threshold of 1 percent of the NAAQS to identify states “linked” to downwind ozone problems sufficient for further evaluation for significant contribution to nonattainment or interference with maintenance of the NAAQS under the good neighbor provision. 81 FR 74518. This same threshold for analysis was used in the CSAPR as to the 1997 ozone NAAQS. See 76 FR at 48237-38.

At Step 3, EPA quantified emissions from upwind states that would significantly contribute to nonattainment or interfere with maintenance by first evaluating various levels of uniform NOX control stringency, each represented by an estimated marginal cost per ton of NOX reduced. EPA then applied the same multi-factor test that was used in the CSAPR to evaluate cost, available emission reductions, and downwind air quality impacts to determine the appropriate level of uniform NOX control stringency that addressed the impacts of interstate transport on downwind nonattainment or maintenance receptors. EPA used this multi-factor assessment to gauge the extent to which emission reductions could be implemented in the future compliance year (i.e., 2017) and to evaluate the potential for over- and under-control of upwind state emissions.

Within the multi-factor test, EPA identified a “knee in the curve,” i.e., a point at which the cost-effectiveness of the emission reductions was maximized, so named for the discernable turning point observable in a multi-factor (i.e., multi-variable) curve. See 81 FR 74550. EPA concluded that this was at the point where emissions budgets reflected a uniform NOX control stringency represented by an estimated marginal cost of $1,400 per ton (2011$) of NOX reduced. This cost threshold in turn represented a control strategy of installing or upgrading combustion controls and optimizing existing SCR controls. In light of this multi-factor test, EPA determined this level of stringency in emissions budgets represented the level at which incremental EGU NOX reduction potential and corresponding downwind ozone air quality improvements were maximized—relative to other control stringencies evaluated—with respect to marginal cost. That is, the ratio of emission reductions to marginal cost and the ratio of ozone improvements to marginal cost were maximized relative to the other levels of control stringency evaluated. EPA found that feasible and cost-effective EGU NOX reductions were available to make meaningful and timely improvements in downwind ozone air quality to address interstate ozone transport for the 2008 ozone NAAQS for the 2017 ozone season. Id. at 74508. Further, the Agency's evaluation showed that emissions budgets reflecting the $1,400 per ton cost threshold did not over-control upwind states' emissions relative to either the downwind air quality problems to which they were linked or the one percent contribution threshold in Step 2 that triggered their further evaluation in Step 3. Id. at 74551-52.

At Step 4, EPA finalized EGU ozone season NOX emissions budgets developed using uniform control stringency represented by $1,400 per ton. These budgets represented emissions remaining in each state after elimination of the amounts of emissions that EPA identified would significantly contribute to nonattainment or interfere with maintenance of the 2008 ozone NAAQS in downwind states. EPA promulgated FIPs requiring the covered power plants in the 22 covered states to participate in the CSAPR NOX Ozone Season Group 2 Trading Program starting in 2017.[55]

b. Partial Nature of the CSAPR Update

At the time it promulgated the CSAPR Update, EPA considered the FIPs to be “partial” and that the rule “may not be sufficient to fully address these states' good neighbor obligations” for the 2008 ozone NAAQS for 21 of the 22 states included in that rule. 81 FR 74508, 74521 (Oct. 26, 2016). Based on information available at the time of the rule's promulgation, EPA was unable to conclude that the CSAPR Update fully addressed most of the covered states' Start Printed Page 68976good neighbor obligations for the 2008 ozone NAAQS. Id. at 74521. Information available at the time indicated that, even with the CSAPR Update implementation, several downwind receptors were expected to continue having problems attaining and maintaining this NAAQS and that emissions from upwind states were expected to continue to contribute greater than or equal to one percent of the NAAQS to these areas during the 2017 ozone season. Id. at 74551-52. Further, EPA could not conclude at that time whether additional EGU and non-EGU reductions implemented on a longer timeframe than 2017 would be necessary, feasible, and cost-effective to address states' good neighbor obligations for this NAAQS.

Additionally, EPA determined it was not feasible to complete an emissions control analysis that may otherwise have been necessary to evaluate full elimination of each state's significant contribution to nonattainment or interference with maintenance and also ensure that emission reductions already quantified in the rule would be achieved by 2017. Id. at 74522. EPA was unable to fully consider both non-EGU ozone season NOX reductions and further EGU reductions that may have been achievable after 2017. Id. at 74521. See Section V.D.3 below.

Thus, EPA also could not make an emissions reduction-based conclusion that the CSAPR Update would fully resolve states' good neighbor obligations with respect to the 2008 ozone NAAQS because the reductions evaluated and required by the CSAPR Update were limited in scope (both by technology and sector). As a result of the remaining air quality problems and the limitations on EPA's analysis, for all but one of the 22 affected states, EPA did not determine in the CSAPR Update that the rule fully addressed those states' downwind air quality impacts under the good neighbor provision for the 2008 ozone NAAQS. Id. at 74521. For one state, Tennessee, EPA determined in the final CSAPR Update that Tennessee's emissions budget fully eliminated the state's significant contribution to downwind nonattainment and interference with maintenance of the 2008 ozone NAAQS because the downwind air quality problems to which the state was linked were projected to be resolved with implementation of the CSAPR Update. Id. at 74552.

c. The CSAPR Close-Out

Following implementation of the CSAPR Update and the approval of Kentucky's SIP (under a court-ordered deadline),[56] on December 21, 2018, EPA issued the CSAPR “Close-Out” to address any good neighbor obligations that remained for the 2008 ozone NAAQS for the 20 remaining states in the CSAPR Update region. See 83 FR 65878 (Dec. 21, 2018). The CSAPR Close-Out made a determination that, based on additional information and analysis, the CSAPR Update fully addressed the remaining 20 affected states' good neighbor obligations for the 2008 ozone NAAQS. In particular, EPA determined that 2023 was an appropriate future analytic year considering relevant attainment dates and the time EPA estimated to be necessary to implement new NOX control technologies at EGUs. Based on EPA's analysis of projected air quality in that year, EPA determined that, for the purposes of addressing good neighbor obligations for the 2008 ozone NAAQS, there would be no remaining nonattainment or maintenance receptors in the eastern U.S. As a result of this determination, EPA found that, with continued implementation of the CSAPR Update, these 20 states would no longer contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the 2008 ozone NAAQS. Id.

d. D.C. Circuit Decisions in Wisconsin v. EPA and New York v. EPA

The CSAPR Update was subject to petitions for judicial review, and the D.C. Circuit issued its opinion in Wisconsin v. EPA on September 13, 2019. 938 F.3d 303. The D.C. Circuit upheld the CSAPR Update in all respects save one: The court concluded that the CSAPR Update was inconsistent with the CAA to the extent that 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 downwind states' 2018 Moderate attainment date. Id. at 313.

The court identified three bases for this holding: (1) The D.C. Circuit's prior opinion in North Carolina v. EPA, 531 F.3d 896 (2008), which held, in the context of CAIR, that the good neighbor provision requires states to eliminate significant contribution “consistent with the provisions” of Title I of the CAA, including the attainment dates applicable in downwind areas, 938 F.3d at 314 (citing 531 F.3d at 912); (2) the unreasonableness of EPA's interpretation of the phrase “consistent with the provisions [of Title I]” in the good neighbor provision as allowing for variation from the attainment schedule in CAA section 181 because it would enable significant contribution from upwind states to continue beyond that statutory timeframe, 938 F.3d at 315-18; and (3) the court's finding that the practical obstacles EPA identified regarding why it needed more time to implement a full remedy did not rise to the level of an “impossibility,” id. at 318-20. With respect to the third basis, the court also found EPA must make a higher showing of uncertainty regarding non-EGU point-source NOX mitigation potential before declining to regulate such sources. Id. at 318-20.

However, the court identified flexibilities that EPA retains in administering the good neighbor provision, acknowledging that EPA has latitude in defining which upwind contribution “amounts” count as significant and thus must be abated, permitting EPA to consider, among other things, the magnitude of upwind states' contributions and the cost associated with eliminating them. 938 F.3d at 320. The court further noted that, in certain circumstances, EPA can grant extensions of the attainment deadlines under the Act; for instance, the court cited CAA section 181(a)(5), which allows EPA to grant one-year extensions from attainment dates under certain circumstances. Id. Finally, the court noted that EPA can attempt to show “impossibility.” Id. The court also recognized that the statutory command that compliance with the good neighbor provision must be achieved consistent with Title I might be read, upon a sufficient showing of necessity, to allow some deviation from downwind deadlines, so long as it is rooted in Title I's framework and provides a sufficient level of protection to downwind States. Id.

The court in Wisconsin remanded but did not vacate the CSAPR Update, finding that vacatur of the rule could cause harm to public health and the environment or disrupt the trading program EPA had established and that the obligations imposed by the rule may be appropriate and sustained on remand. Id. at 336. The court also rejected petitioners' request to place EPA on a six-month schedule to address the remand, noting the availability of “mandamus” relief before the D.C. Circuit should EPA fail to “modify the rule in a manner consistent with our opinion.” Id. at 336-37.

On October 1, 2019, in a judgment order, the D.C. Circuit vacated the CSAPR Close-Out on the same grounds Start Printed Page 68977that it remanded the Update in Wisconsin. New York v. EPA, 781 Fed. App'x 4 (D.C. Cir. 2019). Because the Close-Out analyzed the year 2023 rather than 2021 (“the next applicable attainment date”) and failed to demonstrate that it was impossible to address significant contribution by the 2021 attainment date, the court found the rule ran afoul of the Wisconsin holding. Id. at 7. “As the EPA acknowledges, the Close-Out Rule `relied upon the same statutory interpretation of the Good Neighbor Provision' that we rejected in Wisconsin. Thus, the Agency's defense of the Close-Out Rule in these cases is foreclosed.” Id. at 6-7 (internal citation omitted). The court left open the possibility that the flexibilities identified in Wisconsin, 938 F.3d at 320, and outlined above, may be available to EPA on remand. Id.

Following Wisconsin and New York, EPA on remand must address good neighbor obligations for the 21 states within the CSAPR Update region for which the Update was only a partial remedy. As explained in the following section, EPA already retains FIP authority as to 20 of these states. In addition, EPA is proposing action pursuant to CAA section 110(k)(6) (42 U.S.C. 7410(k)(6)) to find that Kentucky's SIP was approved in error and is thus proposing a FIP for Kentucky consistent with the obligations proposed for the other remaining CSAPR Update region states.

2. FIP Authority for Each State Covered by the Proposed Rule

On March 12, 2008, EPA promulgated a revision to the ozone NAAQS, lowering both the primary and secondary standards to 75 ppb. See National Ambient Air Quality Standards for Ozone, Final Rule, 73 FR 16436 (March 27, 2008). Specifically, the standards require that an area may not exceed 0.075 parts per million (75 ppb) using the 3-year average of the fourth highest 24-hour maximum 8-hour rolling average ozone concentration. These revisions of the NAAQS, in turn, triggered a 3-year deadline for states to submit SIP revisions addressing infrastructure requirements under CAA sections 110(a)(1) and 110(a)(2), including the good neighbor provision. Several events affected the timely application of the good neighbor provision for the 2008 ozone NAAQS, including reconsideration of the 2008 ozone NAAQS and legal developments pertaining to the CSAPR, which created uncertainty surrounding EPA's statutory interpretation and implementation of the good neighbor provision.[57] Notwithstanding these events, EPA ultimately affirmed that states' good neighbor SIPs were due on March 12, 2011.

a. FIP Authority for CSAPR Update States

EPA subsequently took several actions that triggered EPA's obligation under CAA section 110(c) to promulgate FIPs addressing the good neighbor provision for several states.[58] First, on July 13, 2015, EPA published a rule finding that 24 states failed to make complete submissions that address the requirements of section 110(a)(2)(D)(i)(I) related to the interstate transport of pollution as to the 2008 ozone NAAQS. See 80 FR 39961 (effective August 12, 2015). This finding triggered a two-year deadline for EPA to issue FIPs to address the good neighbor provision for these states by August 12, 2017. The CSAPR Update finalized FIPs for 13 of these states (Alabama, Arkansas, Illinois, Iowa, Kansas, Michigan, Mississippi, Missouri, Oklahoma, Pennsylvania, Tennessee, Virginia, and West Virginia), requiring their participation in a NOX trading program. EPA also determined in the CSAPR Update that the Agency had no further FIP obligation as to nine additional states identified in the finding of failure to submit because these states did not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the 2008 ozone NAAQS. See 81 FR 74506.[59 60] On June 15, 2016, and July 20, 2016, EPA published additional rules finding that Maryland and New Jersey, respectively, also failed to submit transport SIPs for the 2008 ozone NAAQS. See 81 FR 38963 (June 15, 2016) (New Jersey, effective July 15, 2016); 81 FR 47040 (July 20, 2016) (Maryland, effective August 19, 2016). The finding actions triggered two-year deadlines for EPA to issue FIPs to address the good neighbor provision for Maryland by August 19, 2018, and for New Jersey by July 15, 2018. The CSAPR Update also finalized FIPs for these two states.

In addition to these findings, EPA finalized disapproval or partial disapproval actions for good neighbor SIPs submitted by Indiana, Kentucky, Louisiana, New York, Ohio, Texas, and Wisconsin.[61] These disapprovals triggered EPA's obligation to promulgate FIPs to implement the requirements of the good neighbor provision for those states within two years of the effective date of each disapproval or, in the case of Kentucky, within two years of the issuance of the judgment in a subsequent Supreme Court decision.[62] EPA promulgated FIPs in the CSAPR Update for each of these states.

As discussed in more detail above in section V.C.1, in issuing the CSAPR Update, EPA did not determine that it had entirely addressed EPA's outstanding CAA obligations to implement the good neighbor provision with respect to the 2008 ozone NAAQS for 21 of 22 states covered by that rule. Accordingly, the CSAPR Update did not fully satisfy EPA's obligation under CAA section 110(c) to address the good neighbor provision requirements for those states by approving SIPs, issuing FIPs, or some combination of those two actions. EPA found that the CSAPR Update FIPs fully addressed the good neighbor provision for the 2008 ozone NAAQS only with respect to Tennessee.Start Printed Page 68978

b. Correction of EPA's Determination Regarding Kentucky's SIP Revision and Its Impact on EPA's FIP Authority for Kentucky

After promulgating the CSAPR Update and before promulgating the CSAPR Close-Out, EPA approved a SIP from Kentucky resolving that state's good neighbor obligations for the 2008 ozone NAAQS. 83 FR 33730 (July 17, 2018). The action was separate from the CSAPR Close-Out because it was taken in response to a May 23, 2017 order from the U.S. District Court for the Northern District of California requiring EPA to take a final action fully addressing the good neighbor obligation for the 2008 ozone NAAQS for Kentucky by June 30, 2018.[63] EPA was obligated to address the outstanding obligation by either approving a SIP submitted by Kentucky or promulgating a FIP to address any remaining obligation.[64]

On May 10, 2018, Kentucky submitted a final SIP to EPA, on which the Agency finalized approval consistent with the court-ordered deadline. See 83 FR 33730. The Kentucky SIP revision that EPA approved relied on the reductions from the CSAPR Update FIP for Kentucky and provided a technical analysis, including emission projections and air quality modeling for 2023, showing that with the CSAPR Update level of reductions, the receptors to which Kentucky was linked were attaining and maintaining the 2008 ozone NAAQS in 2023. This allowed EPA to conclude that Kentucky did not have any further obligation for the 2008 ozone NAAQS, and EPA approved the SIP revision. Thus, the approval relied on the same rationale and technical analysis that was eventually used for the other CSAPR Update FIP states in the CSAPR Close-Out. EPA's approval stated:

“no additional emission reductions are necessary to address the good neighbor provision for the 2008 ozone NAAQS beyond those required by the Cross-State Air Pollution Rule Update (CSAPR Update) federal implementation plan (FIP). Accordingly, EPA is approving Kentucky's submission because it partially addresses the requirements of the good neighbor provision for the 2008 ozone NAAQS, and it resolves any obligation remaining under the good neighbor provision after promulgation of the CSAPR Update FIP. The approval of Kentucky's SIP submission and the CSAPR Update FIP, together, fully address the requirements of the good neighbor provision for the 2008 ozone NAAQS for Kentucky.”

83 FR 33730.

Subsequent to EPA's approval of the Kentucky SIP, EPA issued the CSAPR Close-Out, which concluded that, based on essentially the same analysis used for Kentucky, none of the other 20 CSAPR Update states had further good neighbor obligations to address the 2008 8-hour ozone NAAQS. In the Fall of 2019, the D.C. Circuit issued the Wisconsin and New York decisions remanding the CSAPR Update Rule and vacating the CSAPR Close-Out (see Section V.C.1.d.).

Kentucky's CSAPR Update FIP, which Kentucky relied on in its SIP revision, is part of the CSAPR Update remand, and EPA must address it in this action. Further, the D.C. Circuit's review of the CSAPR Close-Out found fault with, and vacated, the same rationale that EPA had used to approve Kentucky's SIP in June 2018.

Therefore, in light of the remand of Kentucky's CSAPR Update FIP in Wisconsin and vacatur of the CSAPR Close-Out in New York, EPA is proposing to determine in this action that its approval of Kentucky's SIP as fully resolving the state's 2008 ozone NAAQS good neighbor obligations was in error. Section 110(k)(6) of the CAA (42 U.S.C. 7410(k)(6)) 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. The court's remand of the partial FIP for Kentucky in Wisconsin and the vacatur of EPA's conclusions for states identically situated to Kentucky in the CSAPR Close-Out means that EPA's approval of Kentucky's SIP was in error. EPA is compelled on remand to act consistently with the court's opinion and has reassessed Kentucky's good neighbor obligations under the 2008 ozone NAAQS here. In doing so, EPA's proposed analysis identifies an additional emission reduction obligation for Kentucky. Therefore, EPA is proposing to correct the error in Kentucky's SIP approval through this notice and comment rulemaking, as allowed by the CAA when a prior SIP approval was in error. The proposed error correction under CAA section 110(k)(6) would revise the approval of Kentucky's SIP to a disapproval and rescind any statements that the SIP submission fully addresses the requirements of the good neighbor provision for the 2008 ozone NAAQS for Kentucky. The Kentucky approval relied on the same analysis which the D.C. Circuit determined to be unlawful in the CSAPR Close-Out, because it only addressed conditions in 2023 without a showing of impossibility regarding the next attainment date in 2021. Kentucky's remanded partial FIP has been reassessed in this action, consistent with EPA's methodology to address the other 20 states with remanded CSAPR Update FIPs, and consistent with the D.C. Circuit's direction in Wisconsin and New York. As discussed in greater detail in the sections that follow, EPA proposes to determine that there are additional emission reductions that are required for Kentucky to fully satisfy its good neighbor obligation for the 2008 ozone NAAQS. The analysis on which EPA proposes this conclusion for Kentucky is the same, regionally consistent analytical framework on which the Agency proposes action for all of the other CSAPR Update states with remanded FIPs. The Agency recognizes that it is possible, based on updated information for the final rule—as applied within a regionally consistent analytical framework—that Kentucky (or other states for which EPA proposes revised FIPs in this action) may be found to have no further interstate transport obligation for the 2008 ozone NAAQS. If such a circumstance were to occur, EPA anticipates that it would not finalize this proposed error correction or may modify the error correction such that our July 2018 approval of Kentucky's SIP may be affirmed.

c. CSAPR Update SIP Revisions That Do Not Affect FIP Authority

Subsequent to the promulgation of the CSAPR Update, EPA approved SIPs fully replacing the CSAPR Update FIPs for Alabama, Indiana, and Missouri.[65] In those SIP approvals and consistent with the conclusions of the CSAPR Update, EPA found that the SIPs partially satisfy Alabama's, Indiana's, and Missouri's good neighbor obligations for the 2008 ozone NAAQS. Thus, EPA continues to have an obligation to fully address good neighbor requirements for the 2008 ozone NAAQS with respect to Alabama and Missouri, stemming from the July 13, 2015, findings of failure to submit, and Indiana, due to the June 15, 2016, disapproval of the state's good neighbor SIP. See 80 FR 39961; 81 FR 38957. Other states have also submitted 2008 ozone NAAQS good neighbor SIPs or Start Printed Page 68979SIPs to replace their CSAPR FIPs, some of which EPA has approved and some of which still remain pending. Because these circumstances do not affect the scope or basis for this rulemaking, these actions are not described in detail in this section.

d. Summary of Authority for FIPs for This Action

Table V.C-1 summarizes the statutory deadline for EPA to address its FIP obligation under CAA section 110(c) and the event that activated EPA's obligation for each of the 21 CSAPR Update states that are the subject of this final action. For more information regarding the actions triggering EPA's FIP obligation and EPA's action on SIPs addressing the good neighbor provision for the 2008 ozone NAAQS, see the memorandum, “Proposed Action, Status of 110(a)(2)(D)(i)(I) SIPs for the 2008 Ozone NAAQS,” in the docket for this action.

Table V.C-1—Actions That Activated EPA's Statutory FIP Deadlines

StateType of action (Federal Register citation, publication date)Statutory FIP deadline 
AlabamaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
ArkansasFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
IllinoisFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
IndianaSIP disapproval (81 FR 38957, 6/15/2016)7/15/2018
IowaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
KansasFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
KentuckySIP disapproval (78 FR 14681, 3/7/2013)6/2/2016
LouisianaSIP disapproval (81 FR 53308, 8/12/2016)9/12/2018
MarylandFinding of Failure to Submit (81 FR 47040, 7/20/2016)8/19/2018
MichiganFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
MississippiFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
MissouriFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
New JerseyFinding of Failure to Submit (81 FR 38963, 6/15/2016)7/15/2018
New YorkSIP disapproval (81 FR 58849, 8/26/2016)9/26/2018
OhioSIP disapproval (81 FR 38957, 6/15/2016)7/15/2018
OklahomaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
PennsylvaniaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
TexasSIP disapproval (81 FR 53284, 8/12/2016)9/12/2018
VirginiaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
West VirginiaFinding of Failure to Submit (80 FR 39961, 7/13/2015)8/12/2017
WisconsinPartial SIP disapproval as to prong 2 (81 FR 53309, 8/12/2016)9/12/2018
 For states other than Kentucky, the FIP deadline is two years from the effective date of the SIP disapproval or Finding of Failure to Submit, which generally trails the publication date by 30 days. For Kentucky, the FIP deadline is two years after the issuance of the Supreme Court's judgment in EPA v. EME Homer City Generation, L.P., 572 U.S. 489 (2014). See supra note 62.

3. The 4-Step Good Neighbor Framework

The CSAPR and the subsequent CSAPR Update, building on EPA's prior methodologies in the NOX SIP Call and CAIR, established a 4-step process to address the requirements of the good neighbor provision.[66] In this proposed action to address the remand of the CSAPR Update, EPA follows the same steps. These steps are: (1) Identifying downwind receptors that are expected to have problems attaining or 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; (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 downwind, implementing the necessary emissions reductions through enforceable measures.

Step 1—In the 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 assessment of future air quality conditions generally accounts for on-the-books emission reductions and the most up-to-date forecast of future emissions in the absence of the transport policy being evaluated (i.e., base case conditions). The locations of downwind air quality problems are identified as those with receptors that are projected to be unable to attain (i.e., nonattainment receptor) or maintain (i.e., maintenance receptor) the NAAQS. In the CSAPR Update, EPA also considered current monitored air quality data to further inform the projected identification of downwind air quality problems. These same considerations are included for this proposal. EPA is not reopening the definition of nonattainment and maintenance receptors promulgated in the CSAPR Update. Further details and application of Step 1 for this proposal are described in section VI.

Step 2—The CSAPR and the 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 problem receptor (i.e., nonattainment or maintenance receptor identified in Step 1) were identified as needing further evaluation for actions to address transport if their air quality was impacted.[67] EPA evaluated a given state's contribution based on the average relative downwind impact calculated over multiple days.[68] States whose air Start Printed Page 68980quality impacts to all downwind problem receptors were below this threshold did not require further evaluation for actions to address transport—that is, these states were determined to not contribute to downwind air quality problems and therefore had no emission reduction obligations under the good neighbor provision. EPA has used this threshold because a notable portion of the transport problem in the eastern half of the United States can result from relatively small contributions from a number of upwind states. Use of the 1 percent threshold for the CSAPR is discussed in the preambles to the proposed and final CSAPR rules. See 75 FR 45237 (Aug. 2, 2010); 76 FR 48238 (Aug. 8, 2011). The same metric is discussed in the CSAPR Update Rule. See 81 FR 74538. While EPA has updated its air quality data for determining contributions, the Agency is not reopening the use of the 1 percent threshold in this action to address the remand of the CSAPR Update. Application of Step 2 for this proposal is described in section VI.

Step 3—For states that are linked in Step 2 to downwind air quality problems, the CSAPR and the CSAPR Update evaluated NOX reductions that were available in upwind states by applying a uniform control technology (represented by a marginal cost of NOX emissions) to entities in these states. EPA evaluated NOX reduction potential, cost, and downwind air quality improvements available at several cost thresholds in the multi-factor test. In both the CSAPR and the CSAPR Update, EPA selected the cost-threshold that maximized cost-effectiveness (of the cost thresholds examined), that is, the level of stringency in emission budgets at which incremental NOX reduction potential and corresponding downwind ozone air quality improvements are maximized with respect to marginal cost relative to the other emission budget levels evaluated. See, e.g., 81 FR 74550. This evaluation quantified the magnitude of emissions that significantly contribute to nonattainment or interfere with maintenance of a NAAQS downwind and apportioned upwind responsibility among linked states, an approach upheld by the U.S. Supreme Court in EPA v. EME Homer City.[69] In general, EPA proposes in this action to apply this approach to identify NOX emission reductions necessary to address significant contribution for the 2008 ozone NAAQS.

In EME Homer City, the Supreme Court held that “EPA cannot require a State to reduce its output of pollution by more than is necessary to achieve attainment in every downwind State or at odds with the one-percent threshold the Agency has set.” 572 U.S. at 521. The Court acknowledged that “instances of `over-control' in particular downwind locations may be incidental to reductions necessary to ensure attainment elsewhere.” Id. at 492.

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

Id. at 522 (footnotes excluded).

The Court further explained that “while EPA has a statutory duty to avoid over-control, the Agency also has a statutory obligation to avoid `under-control,' i.e., to maximize achievement of attainment downwind.” Id. at 523. Therefore, in the CSAPR Update, 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 81 FR at 74551-52. This evaluation of cost, NOX reductions, and air quality improvements, including consideration of potential over-control, results in EPA's determination of upwind emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS downwind and should therefore be eliminated. This allows EPA to then determine an enforceable emissions limit (often embodied in the form of an emissions budget) for the covered sources. Emissions budgets are the remaining allowable emissions after the elimination of emissions identified as significantly contributing to nonattainment or interfering with maintenance of the standard downwind.

In both the CSAPR and the CSAPR Update, EPA focused its Step 3 analysis on EGUs. In the CSAPR Update, EPA did not quantify non-EGU stationary source emissions reductions to address interstate ozone transport for the 2008 ozone NAAQS for two reasons. First, EPA explained that there was greater uncertainty in EPA's assessment of non-EGU NOX mitigation potential, and that more time would be required for states and EPA to improve non-EGU point source data and pollution control assumptions before it could develop emission reduction obligations based on that data. See 81 FR 74542. Second, EPA explained that it did not believe that significant, certain, and meaningful non-EGU NOX reduction was in fact feasible for the 2017 ozone season. Id. In Wisconsin, the D.C. Circuit found that the practical obstacles EPA identified with respect to its evaluation of non-EGUs did not rise to the level of an “impossibility,” 938 F.3d at 318-20. The court also found that EPA must make a higher showing of uncertainty regarding non-EGU point-source NOX mitigation potential before declining to regulate such sources on such a basis, id. Therefore, as discussed in more detail in Section VII, in this proposed action on remand from Wisconsin, EPA has included all major stationary source sectors in the linked upwind states in its “significant contribution” analysis at Step 3 of the 4-step framework.

Step 4—CSAPR and the CSAPR Update established interstate trading programs to implement the necessary emission reductions. Each state subject to the program is assigned an emissions budget for the covered sources. 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 in an amount equal to their ozone season EGU NOX emissions.

EPA's trading programs under the good neighbor provision allow for interstate trading. However, in order to ensure that each state achieves reductions proportional to the level of their significant contribution, beginning with the CSAPR, EPA established “assurance levels” set as percentage of each state's budget (e.g., 121 percent) above which emissions from sources in that state become subject to a higher “penalty” surrender ratio. These assurance levels are designed to allow for a certain level of year-to-year Start Printed Page 68981variability within power sector emissions to account for fluctuations in demand and EGU operations. The levels are therefore set by determining a “variability limit,” calculated based on an analysis of the historical level of variability in EGU operations.

Thus, both the CSAPR and the CSAPR Update set assurance levels equal to the sum of each state's emissions budget plus its variability limit. The CSAPR and the CSAPR Update 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 responsive to previous court decisions (see discussion in section VIII.C.2 of this preamble) and was not part of the CSAPR Update aspects remanded to EPA in Wisconsin. EPA proposes to apply the same variability limits and assurance provisions in this rulemaking.[70] Implementation using a CSAPR trading program is further described in section VIII of this notice.

VI. Analyzing Downwind Air Quality and Upwind-State Contributions

In this section, EPA describes the air quality modeling and analyses performed to identify nonattainment and/or maintenance receptors and evaluate interstate contributions to these receptors from individual upwind states for the 2021 analytic year. Although the air quality modeling was performed using an air quality modeling platform that covers the contiguous 48 states, the analysis to identify receptors and evaluate contributions focuses on the 21 upwind states that are the subject of this rule.

The year 2021 was selected as the appropriate future analytic year for this rule because it coincides with the July 20, 2021, Serious area attainment date under the 2008 ozone NAAQS. In the CSAPR Update, EPA had aligned its analysis and implementation of emission reductions with the 2017 ozone season (ozone seasons run each year from May 1-September 30) in order to assist downwind states with timely attainment of the 2008 ozone NAAQS by the Moderate area attainment date of July 20, 2018. See 81 FR 74516. 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. Similarly, for the Serious area attainment date in 2021, states will rely on design values calculated using ozone season data from 2018 through 2020. However, it is not possible to impose emission reductions on upwind states in the 2020 ozone season, which has already passed. Reductions in the 2021 ozone season will nonetheless occur in time for the 2021 attainment date and therefore assist downwind states in achieving attainment by the July 20, 2021 attainment date, in compliance with the Wisconsin holding. See Wisconsin, 938 F.3d at 309 (the CSAPR Update is unlawful to the extent it allowed upwind states to “continue their significant contributions to downwind air quality problems beyond the statutory deadlines by which downwind States must demonstrate their attainment of air quality standards”) (emphasis added). Further, EPA continues to interpret the good neighbor provision as forward-looking, based on Congress's use of the future-tense “will” in section 110(a)(2)(D)(i), an interpretation upheld in Wisconsin, 938 F.3d at 322. It would be “anomalous,” id., for EPA to impose good neighbor obligations in 2021 and future years based solely on finding that “significant contribution” had existed at some time in the past.

EPA has also conducted additional analysis of remaining air quality receptors and contribution in years beyond 2021, in order to ensure a complete Step 3 analysis. EPA has analyzed these later years to determine whether any additional emission reductions that are impossible to obtain by the 2021 attainment date may yet be necessary in order to fully address significant contribution. This 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 and/or necessity. See 938 F.3d at 320. However, for purposes of EPA's initial analysis of air quality at Step 1 of the 4-step framework, in accordance with Wisconsin, EPA has selected the 2021 ozone season, corresponding with the 2021 Serious area attainment date.

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 emission inventories, (2) the method for projecting design values in 2021, and (3) the approach for calculating ozone contributions from upwind states.[71] The Agency also provides the design values for nonattainment and maintenance receptors and the predicted interstate contributions that are at or above the one percent of the NAAQS screening threshold. The 2016 base period and 2021, 2023, and 2028 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.

A. Overview of Air Quality Modeling Platform

EPA used 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 emission projections for 2023 and 2028. The emissions data contained in this platform were developed by EPA, Multi-Jurisdictional Organizations (MJOs), and state and local air agencies as part of the Emissions Inventory Collaborative Process. This process resulted in a common-use set of emissions data for a 2016 base year and 2023 and 2028 that can be leveraged by EPA and states for regulatory air quality modeling.[72] The air quality modeling 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. EPA used the CAMx version 7beta6 for air quality modeling since this was the most recent version of CAMx available at the time the air quality modeling was performed.[73] Additional information on the 2016-based air quality modeling platform can be found in the AQM TSD.

B. Emissions Inventories

EPA developed emission inventories for this proposal, including emission estimates for EGUs, non-EGU point sources, stationary nonpoint sources, Start Printed Page 68982onroad mobile sources, nonroad mobile sources, wildfires, prescribed fires, and biogenic emissions that are not the result of human activities. EPA's air quality modeling relies on this comprehensive set of emission inventories because emissions from multiple source categories are needed to model ambient air quality and to facilitate comparison of model outputs with ambient measurements.

To prepare the emission inventories for air quality modeling, EPA processed the emission inventories using the Sparse Matrix Operator Kernel Emissions (SMOKE) Modeling System version 4.7 to produce the gridded, hourly, speciated, model-ready emissions for input to the air quality model. Additional information on the development of the emission inventories and on data sets used during the emissions modeling process are provided in the Technical Support Document (TSD) “Preparation of Emissions Inventories for the 2016v1 North American Emissions Modeling Platform,” hereafter known as the “Emissions Modeling TSD.” This TSD is available in the docket for this rule and at https://www.epa.gov/​air-emissions-modeling/​2016v1-platform .

1. Foundation Emission Inventory Data Sets

Emissions data were developed that represented the year 2016 to support air quality modeling of a base year from which future air quality could be forecasted. As noted above, EPA used the Inventory Collaborative 2016 version 1 (2016v1) Emissions Modeling Platform, released in October 2019, as the primary basis for the inventories supporting the air quality modeling. This platform was developed through a national collaborative effort between EPA and state and local agencies along with MJOs. The original starting point for the U.S. portions of the 2016 inventory was the 2014 National Emissions Inventory (NEI), version 2 (2014NEIv2), although 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 future base case inventories developed for 2023 and 2028 represent projected changes in activity data and predicted emission reductions from on-the-books actions, planned emission control installations, and promulgated federal measures that affect anthropogenic emissions.[74]

2. Development of Emission Inventories for EGUs

Annual NOX and SO2 emissions for EGUs in the 2016 base year inventory are based primarily on data from continuous emission monitoring systems (CEMS) and other monitoring systems allowed for use by qualifying units under 40 CFR part 75, with other EGU pollutants estimated using emission factors and annual heat input data reported to EPA. For EGUs not reporting under part 75, EPA used the most recent data submitted to the NEI by the states. Emissions data for sources that did not have data provided for the year 2016 were pulled forward from data submitted for 2014. 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 EPA every year, while the smaller Type B point sources must only be reported to EPA every three years. For more information on how the 2016 EGU emissions data were developed and prepared for air quality modeling, see the Emissions Modeling TSD.

EPA projected future 2023 and 2028 baseline EGU emissions using the version 6—January 2020 reference case of the Integrated Planning Model (IPM).[75 76] 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 emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. EPA has used IPM for over two decades to better understand power sector behavior under future business-as-usual conditions and to evaluate the economic and emission impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible. EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM. The model documentation provides additional information on the assumptions discussed here as well as all other model assumptions and inputs.[77]

The IPM version 6—January 2020 reference base case accounts for updated federal and state environmental regulations, committed EGU retirements and new builds, and technology cost and performance assumptions as of late 2019. This projected base case accounts for the effects of the finalized Mercury and Air Toxics Standards rule, the CSAPR and the CSAPR Update, New Source Review settlements, and other on-the-books federal and state rules through 2019 [78] impacting SO2, NOX, directly emitted particulate matter, and CO2, and final actions EPA has taken to implement the Regional Haze Rule.

Additional 2021 EGU emissions baseline levels were developed through engineering analytics as an alternative approach that did not involve IPM. EPA developed this inventory for use in Step 3 of this proposed rulemaking, where it determines emission reduction potential and corresponding emission budgets. IPM includes optimization and perfect foresight in solving for least cost dispatch. Given that the final rule will likely become effective either immediately prior to or slightly after the start of the 2021 ozone season, EPA adopted a similar approach to the CSAPR Update where it relied on IPM in a relative way in Step 3 to avoid overstating optimization and dispatch decisions that were not possible in the short time frame. EPA does this by using the difference in emission 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 2021 engineering analytics data set is described in more detail in the Ozone Transport Policy Analysis TSD.

3. Development of Emission Inventories for non-EGU Point Sources

The non-EGU point source emissions in the 2016 base case inventory match those in the 2016v1 platform. Some non-EGU point source emissions were based on data submitted for 2016, others were projected from 2014 to 2016, and Start Printed Page 68983the emissions for remaining small sources were kept at 2014 levels. Prior to air quality modeling, the emission inventories were processed into a format that is appropriate for the air quality model to use. Projection factors and percent reductions in this proposal reflect comments received as a result of the Inventory Collaborative development process, along with emission reductions due to national and local rules, control programs, plant closures, consent decrees, and settlements. Reductions from several Maximum Achievable Control Technology and National Emission 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). Details on the development and processing of the non-EGU emissions inventories for 2016, 2023, and 2028 are available in the Emissions Modeling TSD.

For aircraft emissions at airports, the emissions used were based on adjustments to emissions in the 2017 NEI (see https://www.epa.gov/​air-emissions-inventories/​2017-national-emissions-inventory-nei-data for data and a TSD). EPA developed and applied factors to adjust the 2017 emissions to 2016, 2023, and 2028 based on activity growth projected by the Federal Aviation Administration Terminal Area Forecast system, published in 2018.

Emissions at rail yards were represented as non-EGU point sources. The 2016 rail yard emissions are largely consistent with the 2017 NEI rail yard emissions. The 2016, 2023, and 2028 rail yard emissions were developed through the Inventory Collaborative process. The rail yard emissions were interpolated from the 2016 and 2023 emissions. Class I rail yard emissions were projected using the Energy Information Administration's 2019 AEO freight rail energy use growth rate projections for 2016, 2023, and 2028 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, while nonpoint oil and gas emissions were primarily based on a run of EPA Oil and Gas Tool for the year 2016. The 2016 oil and gas inventories were projected to 2023 and 2028 using regional projection factors by product type based on Annual Energy Outlook (AEO) 2018 projections. NOX and VOC reductions that are co-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 are reflected for select source categories. Additional information on the development and modeling of the oil and gas emission inventories can be found in the Emissions Modeling TSD.

4. Development of Emission 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. EPA developed the onroad mobile source emissions for states other than California using EPA's Motor Vehicle Emissions Simulator (MOVES) 2014b. MOVES2014b was used with inputs provided by state and local agencies, where available, in combination with nationally available data sets. Onroad emissions for the platform were developed based on emissions factors output from MOVES2014b 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, and the remaining activity data were derived from the 2014NEIv2. The onroad emissions were computed within SMOKE by multiplying emission factors developed using MOVES with the appropriate activity data. Onroad mobile source emissions for California were consistent with the emissions provided by the state.

The future-year emissions for onroad mobile sources represent all national control programs known at the time of modeling except for the Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2 [79] and the Safer Affordable Fuel-Efficient (SAFE) Vehicles Rule.[80] Finalized rules incorporated into the onroad mobile source emissions include: Tier 3 Standards (March 2014), the Light-Duty Greenhouse Gas Rule (March 2013), Heavy (and Medium)-Duty Greenhouse Gas Rule (August 2011), the Renewable Fuel Standard (February 2010), the Light Duty Greenhouse Gas Rule (April 2010), the Corporate-Average Fuel Economy standards for 2008-2011 (April 2010), the 2007 Onroad Heavy-Duty Rule (February 2009), and the Final Mobile Source Air Toxics Rule (MSAT2) (February 2007). Estimates of the impacts of rules that were in effect in 2016 are included in the 2016 base year emissions at a level that corresponds to the extent to which each rule had penetrated into the fleet and fuel supply by the year 2016. Local control programs such as the California LEV III program are included in the onroad mobile source emissions. The future year onroad emissions reflect projected changes to fuel properties and usage. MOVES was run for the years 2023 and 2028 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 and 2028 using AEO 2019-based factors. The future year emissions were computed within SMOKE by multiplying the future year emission factors developed using MOVES with the year-specific activity data. Additional information on the approach for generating the onroad mobile source emissions is available in the Emissions Modeling TSD.

5. Development of Emission Inventories for Commercial Marine Vessels

The commercial marine vessel (CMV) emissions in the 2016 base case emission 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 and 2028 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. Some minor adjustments to the CMV Start Printed Page 68984emissions were implemented following the October 2019 2016v1 release. These updated CMV inventories were released publicly by February, 2020.[81]

6. Development of Emission Inventories for Other Nonroad Mobile Sources

Nonroad mobile source emission inventories (other than CMV, locomotive, and aircraft emissions) were developed from monthly, county, and process level emissions output from MOVES2014b. MOVES2014b included important updates to nonroad engine population growth rates. 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.

EPA also ran MOVES2014b for 2023 and 2028 to prepare nonroad mobile emissions inventories for future years. The nonroad mobile emission 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.

Line haul locomotives are also considered a type of nonroad mobile source but the emissions inventories for locomotives were not developed using MOVES2014b. Year 2016 locomotive emissions were developed through the Inventory Collaborative and are mostly consistent with those in the 2017 NEI. The projected locomotive emissions for 2023 and 2028 were developed by applying factors to the base year emissions using activity data based on 2018 AEO freight rail energy use growth rate projections and emission rates adjusted to account for recent historic trends.

7. Development of Emission Inventories for Nonpoint Sources

The emissions for stationary nonpoint sources in our 2016 base case emission inventory are largely consistent with those in the 2014NEIv2, although some were adjusted to more closely reflect year 2016 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. For more information on the nonpoint sources in the 2016 base case inventory, see the Emissions Modeling TSD and the 2014NEIv2 TSD.

Where states provided the Inventory Collaborative information about projected control measures or changes in nonpoint source emissions, those inputs were incorporated into the projected inventories for 2023 and 2028. 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 EPA Oil and Gas Tool for 2016. To develop the future year inventories, regional projection factors for nonpoint oil and gas sources were developed by product type based on AEO 2018 projections to 2023 and 2028. Estimates of criteria air pollutant (CAP) co-benefit reductions resulting from the NESHAP for RICE and NSPS rules and Oil and Gas NSPS VOC controls for select source categories were included. Additional details on the application of these rules and projections for nonpoint sources are available in the Emissions Modeling TSD.

C. Air Quality Modeling and Analyses 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 2008 8-hour ozone NAAQS in the 2021 analytic future year. Where EPA's analysis shows that an area or site does not fall under the definition of a nonattainment or maintenance receptor in 2021, that site is excluded from further analysis under EPA's good neighbor framework.

In this proposed rule, EPA is not reopening the approach used in the CSAPR Update to identify nonattainment and maintenance receptors. However, as an aid to understanding EPA's approach to identifying receptors, a summary of this approach follows.

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.[82] 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, 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 EPA defined nonattainment receptors as those areas that both currently monitor nonattainment and that EPA projects will be in nonattainment in the future compliance year.[83]

The Agency explained in the NOX SIP Call and CAIR and then reaffirmed in the CSAPR Update that 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. EPA separately identified maintenance receptors as those receptors that would have difficulty maintaining the relevant NAAQS in a scenario that takes into account 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. 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). EPA also recognizes that previously experienced meteorological conditions (e.g., dominant wind direction, temperatures, air mass patterns) promoting ozone formation that led to maximum concentrations in the measured data may reoccur in the future. The maximum design value Start Printed Page 68985gives a reasonable projection of future air quality at the receptor under a scenario in which such conditions do, in fact, reoccur. 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 value for 2021 at each receptor in relation to the 2008 ozone NAAQS and, where such a value exceeds the NAAQS, EPA determined that receptor to be a “maintenance” receptor for purposes of defining interference with maintenance, consistent with the method used in the CSAPR and upheld by the D.C. Circuit in EME Homer City II.[84] That is, monitoring sites with a maximum design value that exceeds the NAAQS are projected to have a maintenance problem in 2021.

Recognizing that nonattainment receptors are also, by definition, maintenance receptors, EPA often uses the term “maintenance-only” to refer to receptors that are not also nonattainment receptors. Consistent with the methodology described above, monitoring sites with a projected maximum design value that exceeds the NAAQS, but with a projected average design value that is below the NAAQS, are identified as maintenance-only receptors. In addition, those sites that are currently measuring ozone concentrations below the level of the applicable NAAQS, but are projected to be nonattainment based on the average design value and that, by definition, are projected to have a maximum design value above the standard are also identified as maintenance-only receptors.

As described above in section VI.B., EPA is using the 2016 and 2023 base case emissions developed under the EPA/MJO/state collaborative project as the primary source for base year and 2023 future year emissions data for this proposed rule. Because this platform does not include emissions for 2021, EPA developed an interpolation technique based on modeling for 2023 and measured ozone data to determine ozone concentrations for 2021. To estimate average and maximum design values for 2021, EPA first performed air quality modeling for 2016 and 2023 to obtain design values in 2023. The 2023 design values were then coupled with the corresponding 2016 measured design values to estimate design values in 2021 using the interpolation technique described below.

Consistent with EPA's modeling guidance,[85] the 2016 and 2023 air quality modeling results were used in a “relative” sense to project design values for 2023. That is, the ratios of future year model predictions to base year model predictions are used to adjust ambient ozone design values [86] 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, the base period 2014-2018 ambient ozone design value data was used in order to project average and maximum design values in 2023.

The ozone predictions from the 2016 and 2023 air quality model simulations were used to project 2014-2018 average and maximum ozone design values to 2023 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 [87] surrounding the location of the monitoring site to calculate a Relative Response Factor (RRF) for that site.[88] The 2014-2018 average and maximum design values were multiplied by the RRF to project each of these design values to 2023. In this manner, the projected design values are grounded in monitored data, and not the absolute model-predicted 2023 concentrations. In light of comments on the Notice of Data Availability (82 FR 1733; January 6, 2017) and other analyses, EPA also projected 2023 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).[89] Specifically, in the WRF meteorological model those grid cells that are greater than 50 percent overwater are treated as being 100 percent overwater. In such cases the meteorological conditions in the entire grid cell reflect the vertical mixing and winds over water, even if part of the grid cell also happens to be over land with land-based emissions, as can often be the case for coastal areas. Overlaying land-based emissions with overwater meteorology may be representative of conditions at coastal monitors during times of on-shore flow associated with synoptic conditions and/or sea-breeze or lake-breeze wind flows. But there may be other times, particularly with off-shore wind flow when vertical mixing of land-based emissions may be too limited due to the presence of overwater meteorology. Thus, for our modeling EPA calculated 2023 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 2023 average and maximum design values for both the “3 x 3” and “no water” approaches were then paired Start Printed Page 68986with the corresponding base period measured design values at each ozone monitoring site. Design values for 2021 for both approaches were calculated by linearly interpolating between the 2016 base period and 2023 projected values.[90] The steps in the interpolation process for estimating 2021 average and maximum design values are as follows:

(1) Calculate the ppb change in design values between the 2016 base period and 2023;

(2) Divide the ppb change by 7 to calculate the ppb change per year over the 7-year period between 2016 and 2023;

(3) Multiply the ppb per year value by 5 to calculate the ppb change in design values over the 5-year period between 2016 and 2021;

(4) Subtract the ppb change between 2016 to 2021 from the 2016 design values to produce the design values for 2021.

The projected 2021 and 2023 design values using both the “3 x 3” and “no-water” approaches are provided in the AQM TSD.[91] EPA is soliciting public comment on the use of the “3 x 3” and “no water” approaches for this rulemaking (Comment C-2). For this proposed rule, EPA is relying upon design values based on the “no water” approach for identifying nonattainment and maintenance receptors.

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.[92] Therefore, projected design values that are greater than or equal to 76 ppb are considered to be violating the 2008 ozone NAAQS. For those sites that are projected to be violating the NAAQS based on the average design values in 2021, the Agency examined the preliminary measured design values for 2019, which are the most recent available measured design values at the time of this proposal. As noted above, the Agency is proposing 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 76 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 76 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 2021 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 VI.C-1 contains the 2014-2018 base period average and maximum 8-hour ozone design values, the 2021 base case average and maximum design values,[93] and the 2019 preliminary design values for the two sites that are projected to be nonattainment receptors in 2021 and the two sites that are projected to be maintenance-only receptors in 2021.[94] 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 VI.C-1—Average and Maximum 2014-2018 and 2021 Base Case 8-Hour Ozone Design Values and 2019 Preliminary Design Values (ppb) at Projected Nonattainment and Maintenance-Only Sites

Monitor IDStateSiteAverage design value 2014-2018Maximum design value 2014-2018Average design value 2021Maximum design value 20212019 Design value
Nonattainment Receptors
090013007CTStratford83.08376.577.482
090019003CTWestport82.78378.578.982
Maintenance-Only Receptors
090099002CTMadison79.78274.076.182
482010024TXHouston79.38175.577.181
Start Printed Page 68987

D. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions

This section documents the procedures EPA used to quantify the impact of emissions from specific upwind states on 2021 8-hour design values for the identified downwind nonattainment and maintenance receptors. 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 strength 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.

EPA performed nationwide, state-level ozone source apportionment modeling using the CAMx Ozone Source Apportionment Technology/Anthropogenic Precursor Culpability Analysis (OSAT/APCA) technique [95] to quantify the contribution of 2023 base case NOX and VOC emissions from all sources in each state to projected 2023 ozone design values at air quality monitoring sites. The CAMx OSAT/APCA model run was performed for the period May 1 through September 30 using the projected 2023 base case emissions and 2016 meteorology for this time period. As described below, 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).

To determine upwind contributions in 2021 the Agency applied the contributions from the 2023 modeling in a relative manner to the 2021 ozone design values. The analytic steps in the process 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 concentrations for each of the top 10 modeled ozone concentration days in 2023 [96] and then divide the average contribution by the corresponding concentration to obtain a Relative Contribution Factor (RCF) for each monitoring site; and

(3) Multiply the 2021 design values by the 2023 RCF at each site to produce the average contribution metric values in 2021.[97] The resulting 2021 contributions from each tag to each monitoring site in the U.S. along with additional details on the source apportionment modeling and the procedures for calculating contributions can be found in the AQM TSD.

In the source apportionment model run, 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 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);
  • Canada and Mexico—anthropogenic emissions from sources in the portions of Canada and Mexico included in the modeling domain (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.

The average contribution metric is intended to provide a reasonable representation of the contribution from individual states to the projected 2021 design value, 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 largest contribution from each state that is the subject of this rule to 8-hour ozone nonattainment and maintenance receptors in downwind states in 2021 is provided in Table VI.D-1.Start Printed Page 68988

Table VI.D-1.—Largest Contribution to Downwind 8-Hour Ozone Nonattainment and Maintenance Receptors in 2021.

Upwind stateLargest downwind contribution to nonattainment receptors for ozone (ppb)Largest downwind contribution to maintenance-only receptors for ozone (ppb)
Alabama0.110.27
Arkansas0.180.15
Illinois0.810.80
Indiana1.261.08
Iowa0.170.22
Kansas0.130.11
Kentucky0.870.79
Louisiana0.274.68
Maryland1.211.56
Michigan1.711.62
Mississippi0.100.37
Missouri0.360.33
New Jersey8.625.71
New York14.4412.54
Ohio2.552.35
Oklahoma0.200.14
Pennsylvania6.865.64
Texas0.590.36
Virginia1.301.69
West Virginia1.491.55
Wisconsin0.230.23

2. Application of Screening Threshold

EPA evaluated the magnitude of the contributions from each upwind state to downwind nonattainment and maintenance receptors. In Step 2 of the good neighbor framework, 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 of the CSAPR Update states to each downwind nonattainment and/or maintenance receptor that were used for the Step 2 evaluation can be found in the AQM TSD.

As discussed above in section V, EPA is not reopening the air quality screening threshold of 1 percent of the NAAQS used in the CSAPR Update. Therefore, as in the CSAPR Update, EPA uses an 8-hour ozone value for this air quality threshold of 0.75 ppb as the quantification of 1 percent of the 2008 ozone NAAQS.

a. States That Contribute Below the Screening Threshold

Of the 21 states that are the subject of this proposed rule, EPA has determined that the contributions from each of the following states to nonattainment and/or maintenance-only receptors in the 2021 analytic year are below the threshold: Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin. Because these states are considered not to contribute to projected downwind air quality problems, EPA proposes to determine that the CSAPR Update FIPs for these states (or, in the case of Alabama and Missouri, the SIP revisions later approved to replace the states' CSAPR Update FIPs) are a complete remedy to address their significant contribution under the good neighbor provision for the 2008 ozone NAAQS. These states remain subject to the ozone season NOX emission budgets established in the CSAPR Update, and EPA is not reopening the determinations in the CSAPR Update regarding these states.[98]

However, for each of these states, EPA notes that updates to the air quality and contributions analysis for the final rule could change the analysis as to which states have contributions to downwind receptors that meet or exceed the contribution screening threshold. In the event that such analysis conducted for the final rule demonstrates that any of those states that contribute amounts below the threshold in the proposal are projected to contribute amounts greater than or equal to the threshold in the final rule analysis, EPA proposes to apply the same Step 3 analysis applied to the linked states in this proposal and may finalize revised emissions budgets or other requirements (as presented for comment in this proposal) for such states. In order to ensure adequate notice of the potential for this change in our analysis between proposal and final and any resulting emission reduction obligations, EPA has calculated emissions budgets for EGUs in each of these nine states applying the same methodology and determinations used for the linked states in the Step 3 analysis described below. In addition, EPA would anticipate extending its proposed assessment of non-EGU sources (and associated requests for comment) for linked states to these states. Any adjustments in the implementation of the emissions budgets at Step 4 for linked states would also apply in these states. EPA is proposing to extend and apply any such analysis and/or emissions-reduction budgets to these states if, and only if, the final rule air quality modeling and other air quality and contribution analysis identifies a linkage as just described. The updated ozone season NOX emission budgets that may be applied in these states are available in the Ozone Transport Policy Analysis TSD.Start Printed Page 68989

b. States That Contribute at or Above the Screening Threshold

In this proposed rule, states with remanded emission budgets under the CSAPR Update that contribute to a specific receptor in an amount at or above the screening threshold in 2021 are considered linked to that receptor. The ozone contributions and emissions (and available emission reductions) for these states are analyzed further at Step 3, as described in section VII, to determine whether and to what extent emissions reductions might be required from each state.

Based on the maximum downwind contributions in Table VI.D-1, the Step 2 analysis identifies that the following 11 states contribute at or above the 0.75 ppb threshold to downwind nonattainment receptors: Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia. Based on the maximum downwind contributions in Table VI.D-1, the following 12 states contribute at or above the 0.75 ppb threshold to downwind maintenance-only receptors: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia. The levels of contribution between each of these linked upwind state and downwind nonattainment receptors and maintenance-only receptors are provided in Table VI.D-2 and Table VI.D-3, respectively.

Table VI.D-2—Contribution (ppb) From Each Linked Upwind State to Downwind Nonattainment   Receptors in 2021

Upwind stateNonattainment receptors
Stratford, CTWestport, CT
Illinois0.690.81
Indiana0.991.26
Kentucky0.780.87
Louisiana0.270.27
Maryland1.211.20
Michigan1.161.71
New Jersey7.708.62
New York14.4214.44
Ohio2.342.55
Pennsylvania6.726.86
Virginia1.291.30
West Virginia1.451.49

Table VI.D-3—Contribution (ppb) From Each Linked Upwind State to Downwind Maintenance-Only Receptors in 2021

Upwind stateMaintenance-only receptors
Madison, CTHouston, TX
Illinois0.800.02
Indiana1.080.02
Kentucky0.790.02
Louisiana0.154.68
Maryland1.560.00
Michigan1.620.00
New Jersey5.710.00
New York12.540.00
Ohio2.350.00
Pennsylvania5.640.00
Virginia1.690.00
West Virginia1.550.00

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 maintenance under Step 3. EPA proposes that the following 12 States are linked at Step 2: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.

VII. Quantifying Upwind-State NOX Reduction Potential To Reduce Interstate Ozone Transport for the 2008 Ozone NAAQS

A. The Multi-Factor Test

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. This analysis focuses on the 12 states linked at steps 1 and 2 of the framework, as identified in the sections above. Following the existing framework as applied in the CSAPR Update, EPA's assessment of linked upwind state emissions reflects analysis of uniform NOX emission control stringency. The analysis has been extended to include assessment of non-EGU sources in addition to EGU sources in the linked upwind states.

Each level of uniform NOX control stringency is represented by an estimated cost per ton of NOX reduced and is characterized by a set of pollution control measures. EPA applies a multi-factor test—the same multi-factor test that was used in the CSAPR and the CSAPR Update [99] —to evaluate increasing levels of uniform NOX control stringency. The multi-factor test, which is central to EPA's step 3 quantification of significant contribution, considers cost, available emission reductions, and downwind air quality impacts to determine the appropriate level of uniform NOX control stringency that addresses the impacts of interstate transport on downwind nonattainment or maintenance receptors. The uniform NOX emission control stringency, represented by marginal cost (or a weighted average cost in the case of EPA's non-EGU analysis), 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 EPA v. EME Homer City Generation, which held that using such an approach to apportion emission 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, represented by an estimated cost-per-ton of control that is applied across linked upwind states; (2) evaluate potential NOX emission 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 emission reductions, and downwind air quality impacts, while also ensuring that emission reductions do not unnecessarily over-control relative to the contribution threshold or downwind air quality.

For both EGUs and non-EGUs, section VII.B describes the available mitigation technologies considered and their associated cost levels. Section VII.C discusses EPA's application of that information to assess emission reduction potential of the identified control strategies. Finally, section VII.D describes EPA's assessment of associated air quality impacts and EPA's subsequent identification of appropriate control stringencies considering the relevant factors (cost, available emission reductions, and downwind air quality impacts). As discussed in greater detail in section VII.D, EPA's multi-factor test informed EPA's determination of Start Printed Page 68990appropriate EGU NOX ozone season emission budgets necessary to reduce emissions that significantly contribute to nonattainment or interfere with maintenance of the 2008 ozone NAAQS for the 2021 ozone season and subsequent control periods. Application of the multi-factor test to non-EGU sources has led EPA to propose to conclude that emissions reductions from non-EGU sources are not necessary to address significant contribution under the 2008 ozone NAAQS. In light of uncertainty in its current information on emissions, existing controls on emissions sources, and emission-reduction potential for non-EGU sources, however, EPA requests comment on its analysis, and whether, based on updated or more complete information, there may be grounds to find non-EGU emissions reductions are necessary to address significant contribution for the 2008 ozone NAAQS (Comment C-3).

This multi-factor approach is consistent with EPA's approach in the prior CSAPR and CSAPR Update actions. In addition, as was done in the CSAPR Update, EPA evaluated possible over-control by determining if an upwind state is linked solely to downwind air quality problems that could have been resolved at a lower cost threshold, or if upwind states could reduce their emissions below the 1 percent air quality contribution threshold at a lower cost threshold. This analysis is described in section VII.D below.

B. Identifying Levels of Control Stringency

1. EGU NOX Mitigation Strategies

In identifying levels of uniform control stringency for EGUs, EPA reassessed the same NOX control strategies that it had analyzed in the 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) turning on existing idled Selective Non-Catalytic Reduction (SNCRs); (4) installing new SNCRs; and (5) installing new SCRs. For the reasons explained in the EGU NOX Mitigation Strategies TSD included in the docket for this proposed action, EPA determined that for the regional, multi-state scale of this rulemaking, only EGU NOX control strategies 1 and 3 are possible for the 2021 ozone season (fully operating existing SCRs, including both optimizing NOX removal by existing operational SCRs and turning on and optimizing existing idled SCRs; and turning on existing idled SNCRs). As discussed in section VII.B.1.b, EPA notes that it is not possible to install state-of-the-art NOX combustion controls by the beginning of the 2021 ozone season on a regional scale. EPA considers state-of-the-art NOX combustion controls at EGUs to be available by the beginning of the 2022 ozone season.

The following subsections describe EPA's identification of uniform levels of NOX emission control stringencies, each represented by an estimated marginal cost per ton of NOX reduced (in 2016$) and characterized by a set of EGU mitigation technologies.

a. $1,600 per Ton, Representing 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, most operators improved their SCR performance and have continued to maintain that level of improved operation. However, this SCR performance is not universal and some drop has been observed as the CSAPR Update ozone-season allowance price has declined steadily since 2017. For example, recent power sector data from 2019 reveal that, in some cases, operating units have SCR controls that have been idled or are operating partially, and therefore suggest that there remains reduction potential through optimization.[100] EPA finds that optimizing all of these remaining SCRs in the 12 linked states is a readily available approach for EGUs to reduce NOX emissions.

EPA identifies $1,600 per ton as a level of uniform control stringency that represents optimizing SCR controls. EPA's analysis of this level of uniform control stringency is informed by comment on the CSAPR Update proposal and updated information on operation and industrial-input costs that have become available since the CSAPR Update.[101] While the costs of optimizing existing, operational SCRs include only variable costs, the cost of optimizing SCR units that are currently idled back into service considers both variable and fixed costs. 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. EPA performed an in-depth cost assessment for all coal-fired units with SCRs. More information about this analysis is available in the EGU NOX Mitigation Strategies Proposed Rule TSD, which is found in the docket for this proposed rule. The TSD notes that, for the subset of SCRs that are already partially operating, the cost of optimizing is often much lower than the $1,600 per ton marginal cost and often under $800 per ton.

EPA is using the same methodology to identify SCR performance as it did in the CSAPR Update rule. To estimate EGU NOX reduction potential from optimizing, EPA considers the difference between the non-optimized NOX emission rates and an achievable operating and optimized SCR NOX emission rate. To determine this rate in the CSAPR Update, EPA evaluated nationwide coal-fired EGU NOX ozone season emissions data from 2009 through 2015 and calculated an average NOX ozone season emission rate across the fleet of coal-fired EGUs with SCR for each of these seven years. EPA found it prudent to not consider the lowest or second-lowest ozone season NOX emission rates, which may reflect new SCR systems that have all new components (e.g., new layers of catalyst). Data from these new systems are not representative of ongoing achievable NOX emission rates considering broken-in components and routine maintenance schedules. To identify the potential reductions from SCR optimization in this proposed action, EPA followed the same methodology and incorporated the latest reported coal-fired EGU NOX ozone season emissions data. EPA updated the timeframe to include the most recent and best available operational data (i.e., 2009 up through 2019). Considering the emissions data over the full time period of available data results in a third-best rate of 0.08 Pounds per Million British Thermal Units (lb/mmBtu). EPA notes that over half of the SCR-controlled EGUs achieved a NOX emission rate of 0.068 lbs/mmBtu or less over their third-best entire ozone season. Moreover, for the SCR-controlled coal units that EPA identified as having a 2019 emission rate greater than 0.08 lb/mmBtu, EPA verified that in prior years, the majority (over 90 percent) of these Start Printed Page 68991same units had demonstrated and achieved a NOX emission rate of 0.08 lb/mmBtu or less on a seasonal and/or monthly basis. This further supports EPA's determination that 0.08 lb/mmBtu reflects a reasonable emission rate for representing SCR optimization in quantifying state emission budgets as discussed in section VIII.B. This fleet-level emission rate assumption of 0.08 lb/mmBtu for non-optimized units reflects, on average, what those units would achieve when optimized. Some of these units may achieve rates that are lower than 0.08 lb/mmBtu, and some units may operate above that rate based on unit-specific configuration and dispatch patterns. EPA evaluated the feasibility of optimizing idled SCRs for the 2021 ozone season. Based on past practice, EPA finds that idled controls can be restored to operation quickly (less than two months). This timeframe is informed by many electric utilities' previous long-standing practice of utilizing SCRs to reduce EGU NOX emission 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.[102] Therefore, EPA believes that SCR optimization mitigation strategies are available for the 2021 ozone season.

The vast majority of SCR controlled units (nationwide and in the 12 linked states) are already partially operating these controls during the ozone season based on historical 2019 emissions rates. EPA believes that this widely demonstrated seasonal behavior of turning on idled SCRs also supports the Agency's finding that optimizing existing SCR systems currently being operated to some degree within the ozone season, which would necessitate fewer changes to SCR operation relative to restarting idled systems, is also feasible for the 2021 ozone season. Full operation of existing SCRs that are already operating to some extent involves increasing reagent (i.e., ammonia or urea) flow rate, and maintaining and replacing catalyst to sustain higher NOX removal rate operations. Increasing NOX removal by SCR controls that are already operating can be implemented by procuring more reagent and catalyst. EGUs with SCR routinely procure reagent and catalyst as part of ongoing operation and maintenance of the SCR system. In many cases, where EPA has identified EGUs that are operating their SCR at non-optimized NOX removal efficiencies, EGU data indicate that these units historically have achieved more efficient NOX removal rates. Therefore, EPA finds that optimizing existing SCRs currently being operated could generally be done by reverting back to previous operation and maintenance plans. Regarding full operation activities, existing SCRs that are only operating at partial capacity still provide functioning, maintained systems that may only require increased chemical reagent feed rate up to their design potential and catalyst maintenance for mitigating NOX emissions. Units must have adequate inventory of chemical reagent and catalyst deliveries to sustain operations. Considering that units have procurement programs in place for operating SCRs, this may only require updating the frequency of deliveries. This may be accomplished within a few weeks.

b. $1,600 per Ton, Representing Installing State-of-the-Art NOX Combustion Controls

EPA also includes installing state-of-the-art combustion controls in the level of uniform control stringency 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 and/or updated quickly and can substantially reduce EGU NOX emissions. In the 12 states linked to downwind receptors under this proposed rule, approximately 99 percent of coal-fired EGU capacity is equipped with some form of combustion control; however, the control configuration and/or corresponding emission rates at some units indicate they may not currently have state-of-the-art combustion control technology. Upgrading existing combustion controls to state-of-the-art combustion control alone can achieve NOX emission rates of 0.139 to 0.155 lbs/mmBtu,[103] and, once installed, reduce NOX emissions at all times of EGU operation. EPA proposes that the installation of state-of-the-art combustion controls is a readily available approach for EGUs to reduce NOX emissions by the start of the 2022 ozone season.

EPA also finds that, generally, state-of-the-art combustion control upgrades require a short installation time—as little as four weeks to install with a scheduled outage (with permitting, design, order placement, fabrication, and delivery occurring beforehand). Feasibility of installing combustion controls was examined by EPA in CSAPR where industry demonstrated the ability to install state-of-the-art LNB controls on a large unit (800 MW) in under six months. EPA received comments in the CSAPR Update on installation of combustion controls from the Institute of Clean Air Companies.[104] Commenters provided information on the equipment and typical installation time frame for new combustion controls, accounting for all steps, and noted 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 was described as:

  • 4-8 weeks—bid evaluation
  • 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 previous comments and EPA observations on past installations, EPA does not believe that it is possible to obtain installation of these controls between rule finalization and the start of the 2021 ozone season. However, EPA does believe the technology could be installed by the start of the 2022 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. 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 Start Printed Page 68992factor of 70 percent. See the NOX Mitigation Strategies Proposed Rule TSD for additional details. In specifying a representative marginal cost at which state-of-the-art combustion controls are widely available, EPA considered all of these estimated costs and finds that the cost is typically comparable to the EGU NOX control stringency of $1,600 per ton, and hence EPA includes installing state-of-the-art NOX combustion controls in the uniform control stringency level represented by $1,600 per ton of NOX removed.

c. $3,900 per ton, Representing Turning on Idled Existing SNCRs

Turning on idled existing SNCRs can also reduce EGU NOX emissions quickly, using investments in pollution control technologies that have already been made. Compared to no post combustion controls on a unit, SNCRs can achieve a 25 percent reduction on average in EGU NOX emissions (with sufficient reagent). These controls are in use to some degree across the U.S. power sector. In the 12 states identified in this proposed rule, approximately 14 percent of coal-fired EGU capacity is equipped with SNCR. Recent power sector data suggest that, in some cases, SNCR controls have been idled or operating less in 2019 relative to performance in prior years.[105] EPA finds that turning on idled SNCRs is an available approach for EGUs to reduce NOX emissions, and similar to restarting idled SCR controls, could be done in time for the 2021 ozone season.

EPA identifies $3,900 per ton as a level of uniform control stringency that represents turning on and fully operating idled SNCRs. For existing SNCRs that have been idled, unit operators may need to restart payment of some fixed and variable costs associated with these controls. Fixed and variable costs include labor, maintenance and repair, parasitic load, and ammonia or urea. The majority of the total fixed and variable operating costs for SNCR is related to the cost of the reagent used (e.g., ammonia or urea) and the resulting cost per ton of NOX reduction is sensitive to the NOX rate of the unit prior to SNCR operation. For more details on this assessment, refer to the EGU NOX Mitigation Strategies Proposed Rule TSD in the docket for this proposed rule.

d. $5,800 per ton, Representing Installing New SNCRs.

The amount of time needed to retrofit an EGU with new SNCR extends beyond the 2021 Serious area attainment date. However, similar to SCR retrofits discussed in section VII.B.1.e, and consistent with the Wisconsin decision, EPA evaluated potential emission reductions and associated costs from this control technology, and assessed the impacts and need for this emissions control strategy at the earliest point in time when post combustion control installation could be achieved. SNCR installations, while generally having shorter project timeframes (i.e., as little as 16 months for an individual power plant installing controls on more than one boiler), share similar implementation steps with and also need to account for the same regional factors as SCR installations.[106] For example, SNCR installation at the Jeffrey power plant (Kansas) was in the planning phase in 2013 but not in service until 2015.[107] Therefore, EPA finds that more than 16 months would be needed to complete all necessary steps of SNCR development at EGUs on a regional scale. EPA discusses the timing of SNCR and SCR post-combustion retrofits together and in more detail in section VII.C.1.

SNCR technology provides owners a relatively less capital-intensive option for reducing NOX emissions compared to SCR technology, albeit at the expense of higher operating costs on a per-ton basis and less total emission reduction potential. EPA examined the remaining nationwide coal-fired fleet that lack SNCR or other NOX post-combustion control to estimate a representative cost of SNCR installation (on a $ per ton basis). Costs were estimated using the operating and unit characteristics specific to this fleet. As described in the NOX Mitigation Strategies Proposed Rule TSD, EPA proposes that $5,800 per ton is the representative cost of these controls reflecting a cost level at which they are available for a majority of the uncontrolled fleet.

e. $9,600 per ton, Representing Installing New SCRs.

The amount of time needed to retrofit an EGU with new SCR extends beyond the 2021 Serious area attainment date. However, similar to SNCR retrofits discussed above, and consistent with the Wisconsin decision, EPA evaluated potential emission reductions and associated costs from this control technology, as well as assessed the impacts and need for this emissions control strategy at the earliest point in time when their installation could be achieved. The amount of time to retrofit EGUs with new SCR varies between approximately 2 and 4 years depending on site-specific engineering considerations and on the number of installations being considered. In prior actions, EPA has noted 39-48 months as appropriate for regionwide actions when EPA is evaluating multiple installations at multiple locations.[108]

The Agency examined the cost for retrofitting a unit with new SCR technology, which typically attains controlled NOX rates of 0.07 lbs/mmBtu or less. Based on the characteristics of the remaining nationwide coal fleet that does not have a post-combustion control retrofit, EPA determined that for unit and performance characteristics representative of that subgroup, $9,600 per ton was the cost level that represents the point at which the SCR retrofit technology was typically available for the majority of these sources. For more details on this assessment, refer to the EGU NOX Mitigation Strategies Proposed Rule TSD in the docket for this proposed rule.

Generation shifting - Finally, for each of the technologies considered above, EPA evaluates emission reduction potential from generation shifting at that representative dollar per ton level. Shifting generation to lower NOX-emitting or zero-emitting EGUs occurs in response to economic factors. As the cost of emitting NOX increases, it becomes increasingly cost-effective for units with lower NOX rates to increase generation, while units with higher NOX rates reduce generation. Because the cost of generation is unit-specific, this generation shifting occurs incrementally on a continuum. Consequently, there is more generation shifting at higher cost NOX-control levels. Because the Agency Start Printed Page 68993has identified discrete cost thresholds resulting from the full implementation of particular types of emission controls, it is reasonable to simultaneously quantify and include the reduction potential from generation shifting at each cost level up to levels that are consistent with control operation. Including these reductions is important, ensuring that other cost-effective reductions (e.g., fully operating controls) at each cost level can be expected to occur. Generation shifting treatment and results are discussed in greater detail in the NOX Mitigation Strategies Proposed Rule TSD.

In general, when EPA estimates emission reduction potential from generation shifting, EPA finds small amounts of generation shifting to existing lower NOX- emitting or zero-emitting units could occur consistent with the near-term implementation timing for this proposed rule. As a proxy for limiting the amount of generation shifting that is feasible for the near-term ozone seasons, EPA limits its assessment to shifting generation to other EGUs within the same state. EPA believes that limiting its evaluation of shifting generation (which EPA sometimes refers to as re-dispatch) to the amount that could occur within the state represents a conservatively small amount of generation-shifting because it does not capture further potential emission reductions that would occur if generation was shifted more broadly among units in different states within the interconnected electricity grid. EPA seeks comment on the extent to which generation shifting towards lower-emitting resources should be incorporated into the overall EGU emission reductions reflected in the state emission budgets (Comment C-4).

Finally, EPA seeks comment on whether other ozone-season NOX mitigation technologies should be considered (Comment C-5). EPA invites comments on the cost and performance of the above listed technologies and any other potential mitigation technologies. For example, in January of 2020 the New York Department of Environmental Conservation adopted a rule to limit emissions from combustion turbines that operate as peaking units. EPA has not historically considered NOX mitigation technologies for these sources in its rulemakings, such as the CSAPR and the CSAPR Update, but invites comment on their appropriateness for this rulemaking. Separately, location and high emission rates of grid-connected municipal solid waste combustors, generally not covered under EPA's transport rules given their small size and differing purpose, have also led some stakeholders to suggest mitigation measures be considered for those sources. EPA similarly invites comment on mitigation opportunities for all of these mitigation technologies discussed in this section and, in particular, requests comment on its discussion of these additional strategies in the NOX Mitigation Strategies Proposed Rule TSD.

2. Non-EGU NOX Mitigation Strategies

EPA has not regulated emissions from non-EGU sources as part of its regional transport rulemakings since the 1998 NOX SIP Call. In Wisconsin, the D.C. Circuit held that EPA must on remand implement a full remedy by the next attainment date (2021 for this proposed rule), or as soon as possible thereafter on a showing of impossibility, to achieve necessary reductions by that date. 938 F.3d at 320. The court also directed the Agency to address non-EGU sources, unless “the scientific uncertainty is so profound that it precludes EPA from making a reasoned judgment.” Id. at 318-20 (quoting Massachusetts v. EPA, 549 U.S. 497, 534 (2007)). The D.C. Circuit found that the practical obstacles EPA identified with respect to its evaluation of non-EGUs in the CSAPR Update did not rise to the level of an “impossibility,” id. The court also found that EPA must make a higher showing of uncertainty regarding non-EGU point-source NOX mitigation potential before declining to regulate such sources on the basis of “uncertainty.” Id. In this proposed rule, EPA has extended its analysis to include all major stationary source sectors in the linked upwind states, including non-EGU emissions sources in various industry sectors. As discussed in section VI, of the 22 states originally included in the CSAPR Update, EPA proposes in this action that 12 states warrant analysis at step 3 for significant contribution to downwind nonattainment and/or maintenance receptors for the 2008 ozone NAAQS. Therefore, the Agency focused its Step 3 assessment on non-EGU sources in these 12 states. For these sources, EPA retained its focus on NOX as the most effective precursor pollutant for addressing interstate ozone transport at a regional scale. See 82 FR 51238, 51248 (Nov. 3, 2017) (citing 76 FR 48222) and 63 FR 57381.

For non-EGU sources, there are many types of emissions sources or units that emit NOX and many control technologies or combinations of control technologies for these sources or units. As such, there are many approaches to assessing emission reduction potential from non-EGU emissions sources or units. In this assessment, EPA attempted to apply the multi-factor test used for EGUs to determine an appropriate stringency level for non-EGU sources in linked upwind states. EPA identified available control technologies and estimated their costs and potential emissions reductions. The information the Agency currently has regarding implementation timeframes to determine potential air quality impacts in relevant future years was also considered.

To identify levels of control for non-EGU sources, EPA used the Control Strategy Tool (CoST),[109] the Control Measures Database (CMDb), and the projected 2023 inventory from the 2016v1 modeling platform. EPA assessed potential emissions reductions associated with applying controls to emissions units with 150 tons per year (tpy) or more of pre-control NOX emissions in 2023, which is an emissions threshold comparable to 25 MW for EGUs used in prior interstate transport rulemakings. To derive this emissions threshold, EPA used emissions expected from an average 25 MW EGU unit operating at a median heat rate, emission rate, and capacity factor for a coal-fired unit.[110] In CoST, the Agency used the maximum emission reduction strategy [111] to estimate the largest quantity of potential emissions reductions from each emissions source or unit located in the 12 upwind states linked to downwind receptors in this proposed rule. 11 of the 12 upwind states had sources with 150 tpy or more of pre-control NOX emissions in 2023; the projected 2023 emissions inventory did not include non-EGU point sources in New Jersey with pre-control NOx emissions greater than 150 tpy for which CoST had applicable control measures.

For the 12 linked states, EPA categorized the CoST results for control technologies that comprise approximately 92 percent of the total estimated potential emissions Start Printed Page 68994reductions from the non-EGU sources with 150 tpy or more of NOX emissions in these states; [112] those technologies and related emissions sources are summarized in Table VII.B.2-1 below. In tranche one before further refinement and verification, the number of emissions units CoST applied SCR to was 51 and the number of emissions units CoST applied SNCR to was 23. The estimated emissions reductions from those control applications were 12,724 ozone season tons. In tranche two before further refinement and verification, the number of emissions units CoST applied layered combustion to was 49, the number of emissions units CoST applied NSCR or layered combustion to was 65, and the number of emissions units CoST applied ultra-low NOX burner and SCR to was 56. The estimated emissions reductions from those control applications were 17,283 ozone season tons. EPA then calculated a weighted average cost per ton (in 2016$) for estimated potential reductions associated with each control technology and plotted the weighted average cost per ton values. From the resulting curve, EPA identified a clear break point that defined two tranches of potential emissions reductions, as shown in Table VII.B.2-1. For additional details on the curve and the potential emissions reductions in tranches one and two, please see the memorandum titled Assessing Non-EGU Emission Reduction Potential, available in the docket for this proposed rule.

Table VII.B.2-1—Details on Tranches One and Two of Potential Emissions Reductions

TrancheTechnologies/industry sectors or source groupsWeighted average cost (2016$ per ton)Cost range (2016$ per ton)
Tranche OneSCR/Glass Manufacturing, IC Engines SNCR/Cement Manufacturing2,00064 113-5,700
Tranche TwoLayered Combustion/Lean Burn IC Engines NSCR or Layered Combustion/Industrial Rich Burn Natural Gas IC Engines * Ultra-low NOX Burner and SCR/Industrial Boilers5,000-6,6001,400-9,700
Note: * NSCR is non-selective catalytic reduction, a control technology applicable to rich-burn natural gas-fired IC engines.

Given the large number of emissions units in a given industry sector that could require control installation, EPA does not have detailed information on the time needed to install all of the control technologies identified in Table VII.B.2-1. Any installation timing estimates would need to reflect the time needed to install controls across a potentially large number of sources, the time needed to have NOX monitoring installed, and other steps in the permitting and construction processes. EPA previously examined the time necessary to install some of the controls indicated in Table VII.B.2-1 for different industries in the 2016 Final Technical Support Document (TSD) for the Final Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment of Non-EGU NOXEmission Controls, Cost of Controls, and Time for Compliance Final TSD (“CSAPR Update Non-EGU TSD”), which is discussed in Section VII.C.2. EPA expects that the controls for glass furnaces and cement kilns would take at least 2 years to install on a sector-wide basis across the 12-state region affected by this proposed rule. Therefore, based on the information available to us at this time, EPA proposes that the 2023 ozone season is the earliest ozone season by which these non-EGU controls could likely be installed. EPA thus concludes that no NOX controls for non-EGUs included in this cost analysis can be installed by the 2021 ozone season. Additional information on installation times for non-EGU NOX controls can be found in Section VII.C.

3. Mobile Source NOX Mitigation Strategies

Under a variety of CAA programs, 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. 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. EPA factors these standards and associated emission reductions into its baseline air quality assessment in good neighbor rulemaking, including in this action. Such reductions are an important reason for the historical and long-running trend of improving air quality in the United States. These trends help explain why the overall number of receptors and severity of ozone nonattainment problems under the 2008 ozone NAAQS continues to decline. Such 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) [114] 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.[115]

For example, in 2014 EPA promulgated new, more stringent emissions and fuel standards for light-Start Printed Page 68995duty passenger cars and trucks.[116] The fuel standards took effect in 2017, and the vehicle standards are phasing 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).

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.[117] 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, EPA will be proposing NOX emission standards that “reflect the greatest degree of emission 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) requires that standards apply for no less than 3 model years and apply no earlier than 4 years after promulgation.

Given these requirements, EPA is considering implementation of new heavy-duty NOX emission standards beginning in model year 2027. In addition, any new rulemaking process for other mobile source sectors would not achieve actual NOX emissions reductions before 2025, given the lead time necessary for EPA and for manufacturers.

However, EPA's existing regulatory program will continue to reduce NOX emissions into the future, and 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. 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 Emission Reduction Potential

1. EGU Emissions Reduction Potential by Cost Threshold

For EGUs, as discussed in section VII.A, the multi-factor test considers increasing levels of uniform control stringency, where each level is represented by cost per ton of emissions reduced, in combination with consideration of total NOX reduction potential and corresponding air quality improvements. To determine which cost thresholds to use to assess upwind state NOX mitigation potential, EPA evaluated EGU NOX control costs that represent the thresholds at which various control technologies are widely available (described previously in section VII.B.1), the use of certain cost thresholds in previous rules to address ozone transport, and cost thresholds incorporated into state requirements to address ozone nonattainment.

EPA began by determining the appropriate range of costs to evaluate. In the CSAPR Update, $1,400 per ton in 2011$ was the EGU NOX cost threshold relied upon to partially address obligations in time for the 2017 ozone season. This figure represented the lowest marginal cost where EPA expects SCR optimization at all existing SCR controls (including fully idled controls [118] ) to be cost-effective. Based on our assessment of EGU NOX mitigation strategies, this same technology would now have a cost of $1,600 per ton in 2016$.[119] Specifically, the cost of this approach to NOX reduction is the marginal cost of optimizing existing SCRs at higher levels of NOX removal than they are currently achieving if their current rate is greater than 0.08 lb/mmBtu. Given that EPA has already determined this technology is cost-effective and reasonable to consider for significant contribution determination in the CSAPR Update (and those determination were not remanded), EPA has not included a representation of mitigation technologies with any lower cost levels in this proposal's analyses in Step 3. (Further, as explained below, such analysis is not necessary for purposes of checking for overcontrol at the selected cost threshold.)

EPA then evaluated EGU NOX cost thresholds to determine an appropriate upper bound for our assessment. EPA identified $9,600 per ton as an upper bound as it represented the most stringent mitigation technology (SCR retrofit) that EPA identified in its assessment. EPA seeks comment on whether $1,600 per ton is an appropriate minimum and $9,600 per ton is an appropriate maximum uniform cost threshold to evaluate for the purpose of quantifying EGU NOX reductions to reduce interstate ozone transport for the 2008 ozone NAAQS (Comment C-6).

EPA then determined appropriate EGU NOX cost thresholds to evaluate within the range of $1,600 per ton to $9,600 per ton and identified two additional thresholds. Table VII.C.1-1 lists the EGU NOX cost thresholds evaluated and the NOX reduction strategy or policy used to identify each cost threshold. As described above in Section VII.B, these cost thresholds are informed by our assessment of the costs at which EGU NOX control strategies are widely available. Evaluating additional cost thresholds in between the four thresholds EPA identifies here would not yield meaningful insights as to NOX reduction potential. EPA-selected cost thresholds represent the points at which specific control technologies become widely available and thereby where the most significant incremental emission reduction potential is expected. Analyzing costs between these cost thresholds is not expected to reveal significant incremental emission reduction potential that isn't already anticipated at the analyzed cost thresholds.Start Printed Page 68996

Table VII.C.1-1—EGU NOX Cost Thresholds and NOX Reduction Strategies

EGU NOX cost threshold (2016$) 120Technology
$1,600 per tonFully operating all existing post-combustion SCR controls and combustion control installation or upgrade.
$3,900 per tonWidespread availability of restarting idled SNCRs.
$5,800 per tonWidespread availability of new SNCRs.
$9,600 per tonWidespread availability of new SCRs.

EPA proposes that this range and selection of uniform cost thresholds are appropriate to evaluate potential EGU NOX reduction obligations to address interstate ozone transport for the 2008 ozone NAAQS. Because these cost thresholds are linked to costs at which EGU NOX mitigation strategies become widely available in each state, the cost thresholds represent the break points in a marginal cost curve at which the most significant step-changes in EGU NOX mitigation are expected. EPA seeks comment on these uniform technologies and their representative cost thresholds for the purpose of quantifying EGU NOX reductions to reduce interstate ozone transport for the 2008 ozone NAAQS (Comment C-7).

The tables below summarize the emission reduction potentials (in absolute ozone season tonnages) from these technologies across the 12-state region. Table VII.C.1-2 focuses on near-term mitigation technologies while Table VII.C.1-3 includes mitigation technologies with extended time frames for implementation.

Table VII.C.1-2—EGU Ozone-Season Emission Reduction Potential—2021

StateBaseline 2021 OS NOXReduction potential (tons) at various representative marginal cost *
SCR optimization ($1600 per ton)SCR optimization + LNB upgrade ($1600 per ton)SCR/SNCR optimization + LNB upgrade ($3900 per ton)
Illinois9,688243243602
Indiana15,8563,3563,3883,821
Kentucky15,5881,2043,6523,762
Louisiana15,488866171,255
Maryland1,5654368225
Michigan13,8931,1662,1262,351
New Jersey1,346929289
New York3,1875050149
Ohio15,8326,2276,2276,350
Pennsylvania11,5703,4943,4943,779
Virginia4,59248520663
West Virginia15,1651,4792,3522,719
Total123,77017,48922,82925,765
* EPA shows reduction potential from state-of-the-art LNB upgrade as a near-term reduction technology but explains in section VII.B and VII.D that this reduction potential would not be implemented until 2022. Sum of state values may vary slightly from total due to rounding.

Table VII.C.1-3—EGU Ozone-Season Emission Reduction Potential—2025

StateBaseline 2025 OS NOXReduction Potential (tons) at various representative marginal cost levels *
SCR optimization + LNB upgrade ($1600 per ton)SCR/SNCR optimization + LNB upgrade ($3,900 per ton)SCR/SNCR optimization + LNB upgrade + * SNCR retrofit ($5,800 per ton)SCR/SNCR optimization + LNB upgrade + * SCR retrofit ($9,600 per ton)
Illinois8,4782015401,1041,452
Indiana12,7553,3083,6653,9734,490
Kentucky15,5883,6523,7625,0886,736
Louisiana15,4886171,2551,4942,852
Maryland1,56568225225326
Michigan10,8411,2281,4392,3003,527
New Jersey1,34692898989
New York3,16950149149149
Ohio15,9176,2406,3696,3696,791
Pennsylvania11,5703,4943,7793,9223,992
Start Printed Page 68997
Virginia3,912517658658890
West Virginia13,4071,5961,9601,9603,838
Total114,03521,06423,89127,33235,133
* Both tables C.1-2 and C.1-3 include limited generation shifting (reflecting that which would occur at the price level consistent with control operation). It does not factor in generation shifting reduction potential that may be attributable to incremental new builds or incremental retirements. Sum of state values may vary slightly from total due to rounding.

As discussed in section VII.B.1.e, in prior actions, EPA has noted 39-48 months as an appropriate implementation timeframe for regionwide actions when EPA is evaluating multiple installations at multiple locations. The start of the 2024 ozone-season would only allow approximately 36 months from the effective date of this rule for post combustion controls to be regionally installed and operating. The 2025 ozone season represents a period approximately 48 months after EPA anticipates taking final action on this proposal and reflects a more demonstrably possible window for making retrofits on a regional scale. Therefore, EPA proposes that 2025 is the earliest ozone season by which new SNCR or SCR may be installed across multiple EGUs on a regional basis.

Installing new SCR or SNCR controls for EGUs generally involves the following steps: Conducting an engineering review of the facility to determine suitability and project scope; advertising and awarding a procurement contract; obtaining a construction permit; installing the control technology; testing the control technology; and obtaining or modifying an operating permit. These timeframes are intended to accommodate a plant's need to conduct an engineering assessment of the possible NOX mitigation technologies necessary to then develop and send a bid request to potential suppliers. Control specifications are variable based on individual plant configuration and operating details (e.g., operating temperatures, location restrictions, and ash loads). Before making potential large capital investments, plants need to complete these careful reviews of their system to inform and develop the control design they request. They then need to solicit bids, review bid submissions, and award a procurement contract—all before construction can begin.

Scheduled curtailment, or planned outage, for pollution control installation would also be necessary to complete SCR or SNCR projects on a regional scale. Given that peak demand and rule compliance would both fall in the ozone season, sources would likely need to schedule installation projects for the “shoulder” seasons (i.e., the spring and/or fall seasons), when electricity demand is lower than in the summer, reserves are higher, and ozone season compliance requirements are not in effect. If multiple units were under the same timeline to complete the retrofit projects as soon as feasible from an engineering perspective, this could lead to bottlenecks of scheduled outages as each unit attempts to start and finish its installation in roughly the same compressed time period. Thus, any compliance timeframe that would assume installation of new SCR or SNCR controls should be developed to reasonably encompass multiple shoulder seasons to accommodate scheduling of curtailment for control installation purposes and better accommodate the regional nature of the program.[121]

Finally, the time lag observed between the planning phase and in-service date of SCR operations in certain cases also illustrates that site-specific conditions can lead to installation times of four years or longer—even for individual power plants. For instance, SCR projects for units at the Ottumwa power plant (Iowa), Columbia power plant (Wisconsin), and Oakley power plant (California) were all in the planning phase in 2014. By 2016, these projects were under construction with estimated in-service dates of 2018.[122] Further, large-scale projects also illustrate that timelines can extend beyond the general estimate for a single power plant when the project is part of a larger, multifaceted air pollution reduction goal. For instance, the Big Bend power plant in Florida completed a multifaceted project that involved adding SCRs to all four units as well as converting furnaces, over-fire air changes, and making windbox modifications, during which a decade elapsed between the initial planning stages and completion.[123]

EPA notes that differences between these control technologies exist with respect to the potential viability of achieving cost-effective, regional NOX reductions from EGUs. SCR controls generally achieve greater EGU NOX reduction efficiency (up to 90 percent) than SNCR controls (25 percent). EPA observes that for the remaining uncontrolled coal fleet in the 12 states, SCRs are, on average, more expensive on a cost per ton basis. However, the analysis in the NOX Mitigation Strategies Proposed Rule TSD notes that the cost range varies widely for units depending on inlet NOX rate and capacity factor. Therefore, for some units, it is possible that SCR retrofit costs are lower than SNCR costs on a cost per ton basis. Moreover, there are a host of other market and policy drivers that may lead a specific unit to prefer a Start Printed Page 68998SCR retrofit over a SNCR retrofit. As a result, EPA believes it is reasonable to allow sufficient time for EGU operators to assess whether either an SNCR or an SCR would be an appropriate post-combustion control technology choice in response to a multi-state emission control program with the flexibility of interstate allowance trading. To allow for that potential determination, EPA is using an SCR-inclusive planning and installation schedule to represent new post-combustion retrofit potential on a regional basis (be it SNCR or SCR as determined by individual EGU owners under our flexible market-based emission trading program).

Furthermore, SNCR installation at an individual source would render later installation of an SCR less cost-effective, because such a unit would have already expended some unrecoverable capital on the less-effective pollution control technology. As a result, it would be counterproductive to assume EGUs should install the less effective SNCR technology to address a short-run air quality concern under an older and less stringent NAAQS when it may later prove necessary to require the more effective SCR technology to address longer-run air quality concerns under a more stringent NAAQS for the same pollutant. Considering these factors, EPA believes it is appropriate to give particular weight to the timeframe required for implementation of SCR across the region as compared to SNCR to allow sources the flexibility to make the most efficient post-combustion control investment. Historically, units have chosen to retrofit with higher performing SCR at a much greater rate than they have chosen SNCR. For SCR, the total time associated with project development is estimated to be up to 39 months for an individual power plant installing controls on more than one boiler. However, more time is needed when considering installation timing for new SCR controls regionally. EPA has previously determined that a minimum of 48 months (four years) is a reasonable time period to allow to complete all necessary steps of SCR projects at EGUs on a regional scale. This timeframe would allow for regional implementation of these controls (i.e., at multiple power plants with multiple boilers) considering the necessary stages of post-combustion control project planning, shepherding of labor and material supply, installation, coordination of outages, testing, and operation.[124]

In addition to its engineering assessment, EPA looked at historical data to validate this 39-48 month installation timeframe. EPA observed over 12 GW of uncontrolled coal capacity in the linked states covered in this rule. For comparison, EPA looked at the last 15 years of data to see if a similar amount of capacity had come online in a shorter time frame. It observed that it had not. Most notably, the CAIR was finalized in March of 2005 covering much of the Eastern U.S. and drove significant SCR retrofit activity, with incentives for early installation and reductions. From this date, 39-48 months would have placed the SCRs online in the mid 2008 to 2009 time frame. The graphic below illustrates an uptick in coal-fired capacity retrofitted with SCRs in response to the rule (Figure VII.D.2). Most of this capacity comes online in 2009 and 2010. Although EPA data on when sources started planning these controls and whether it was driven purely by CAIR or other factors is not perfect, it finds the chart below consistent with its determination that a 39-48 month time frame is reasonable for SCR retrofit possibility on a regional level.

2. Non-EGU Emission Reduction Potential by Cost Threshold

EPA performed a similar analysis of reduction potential for the non-EGU mitigation technologies identified, as discussed in section VII.B.2 of this notice. EPA identified two tranches of controls for non-EGU emissions sources associated with two levels of weighted average cost per ton. EPA's assessment of emission reduction potential from the controls in these tranches reflects significant uncertainty resulting from the current information available to the Agency. Because information for existing controls on non-EGU emissions sources is missing in the 2016 base year Start Printed Page 68999inventory for some states and incomplete for some sources, EPA went through a process to further verify existing control information and refine the NOX emission reduction potential estimated by CoST, the CMDb, and the 2023 projected inventory. Because of the data- and research-intensive nature of the process, this verification process focused on a subset of the 12 linked states, where the control measures applied resulted in the greatest potential air quality impact. The steps EPA took, discussed in more detail below, include:

  • Considered the air quality impacts by state and focused on upwind states with the largest estimated potential air quality impacts from potential non-EGU emission reductions;
  • Assumed that the potential reductions in tranche one were potentially cost-effective because tranche one's weighted average cost of $2,000 per ton is similar to the proposed control stringency for EGUs represented by $1,600 per ton (see section VII.D.1);
  • Looked at potential emissions reductions in tranche one that were estimated to cost less than $2,000 per ton; and
  • For those potential reductions in tranche one that were estimated to cost less than $2,000 per ton, reviewed online facility permits and industrial trade literature to verify and determine if the estimated emissions reductions may be actual, achievable emissions reductions.

First, to narrow the number of states for which the Agency verified existing control information and refined the NOX emission reduction estimates the Agency considered the potential air quality impacts by state and focused the assessment on the upwind states with the largest estimated potential air quality impacts: Indiana, New York, Ohio, Pennsylvania, and West Virginia.[125] EPA identified these states using an estimate of 0.02 ppb as a threshold for air quality improvement that may be obtained from reductions from non-EGUs in each state. The Agency is not applying a 0.02 ppb impact threshold as a step in the step 3 multi-factor test. Rather, this threshold value allowed the Agency to better target its efforts toward the potentially effective states for non-EGU NOX emissions reductions. For additional discussion on the air quality impacts by state, see the section titled Air Quality Impacts from Potential Non-EGU Emissions Reductions in the technical memorandum titled Assessing Non-EGU Emission Reduction Potential in the docket for this proposed rule.

Next, to narrow the set of emissions sources in those states for which EPA would verify existing control information and refine the NOX emission reduction estimates, the Agency assumed that the potential reductions in tranche one were potentially relatively cost-effective because tranche one's weighted average cost of $2,000 per ton is similar to the proposed control stringency for EGUs represented by $1,600 per ton (see section VII.D.1).

Next, EPA looked at potential emissions reductions in tranche one that were estimated to cost less than $2,000 per ton. Before refining the emission reduction estimates in tranche one, the total estimated emissions reductions for the non-EGU sources in Indiana, New York, Pennsylvania, and Ohio are 7,556 ozone season tons. The estimated emissions reductions in tranche one in those states that cost less than $2,000 per ton are 6,346 ozone season tons, or 84 percent of the total. Note that no potential emissions reductions at a cost of less than $2,000 per ton were identified in West Virginia because CoST originally estimated control costs for two IC engines in West Virginia inappropriately, and CoST did not identify likely cost-effective controls for any other non-EGU emissions units in the state. EPA removed the two IC engines in West Virginia from further consideration because the corrected potential cost was greater than $2,000 per ton. In reviewing the potential controls in tranche one that were estimated to cost less than $2,000 per ton for Indiana, New York, Pennsylvania, and Ohio, EPA found that these reductions were from SCR applied to glass furnaces and SNCR applied to cement kilns.

Next, to verify the information on the application of these controls and estimated emissions reductions, EPA reviewed facilities' online title V permits and industrial trade literature for the likely cost-effective emissions reductions associated with SCR applied to glass furnaces and SNCR applied to cement kilns. Of the 20 emissions units in Indiana, New York, Pennsylvania, and Ohio included in the cost analysis, source permits identified that 10 units (i) already have controls and monitors (primarily CEMS), (ii) are installing controls and CEMS or consolidating operations in the next few years as a result of recent consent decrees issued as part of EPA's New Source Review Air Enforcement Initiative, (iii) have shut down, or (iv) are planning to shut down by 2023. The results of the online permit review and review of industrial trade literature, summarized in Table VII.C.2-1 below, suggest that approximately 14 percent of the CoST-estimated potential emissions reductions in these four states may be possible to achieve. EPA expects that the controls for glass furnaces and cement kilns would take at least 2 years to install on a sector-wide basis across the 12-state region affected by this proposed rule. Therefore, based on the information available to us at this time, EPA believes that the 2023 ozone season is the earliest ozone season by which these non-EGU controls could likely be installed. For additional details on the review of online permits and industrial trade literature, please see the memorandum titled Assessing Non-EGU Emission Reduction Potential, available in the docket for this proposed rule.

Table VII.C.2-1—Status of Potential Emissions Reductions

Number of emissions unitsOS tons(Percent of total)
Shutdowns482413
Lehigh Cement—Kiln Replacements33666
NEI Discrepancy/Uncertain 12613,28651
Already Controlled/Uncertain596715
Start Printed Page 69000
Possible Emissions Reductions790314
TOTAL206,346

EPA has also previously examined the time necessary to install the controls indicated in the table above (with details on the technology tranches) for different industries. The 2016 CSAPR Update Non-EGU TSD provided preliminary estimates of installation times for a variety of NOX control technologies applied to a large number of sources in non-EGU industry sectors.[127] For virtually all NOX controls applied to cement manufacturing and glass manufacturing, information on installation times was not available to provide an estimate, and that the installation time for these controls was “uncertain.” There was an exception for SNCR applied to cement kilns; however, the installation time estimate of 42-51 weeks listed in the CSAPR Update Non-EGU TSD does not account for implementation across multiple sources, the time needed to have NOX monitoring installed, and other steps in the permitting and construction processes.

To improve upon information from the CSAPR Update Non-EGU TSD on installation times for SCR on glass furnaces and SNCR on cement kilns, EPA reviewed information from permitting actions and a consent decree. For two glass manufacturing facilities that installed SCR on glass furnaces, from the time of permit application to the time of SCR operation was approximately 19 months for one facility and is currently at least 20 months for another facility.[128] These installation times do not reflect time needed for pre-construction design and engineering, financing, and factors associated with scaling up construction services for multiple installations at several emissions units. With respect to cement kilns, an April 2013 consent decree between EPA and CEMEX, Inc. required installation of SNCR at a kiln within 450 days, or approximately 15 months, of the effective date of the consent decree. Similarly, this installation time does not reflect time associated with scaling up construction services for multiple control installations at several emissions units.

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 industry sectors on a regional basis is a relatively fast installation timeframe. A shorter installation timeframe of approximately one year (i.e., in time for the 2022 ozone season) would 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.[129]

Thus, for purposes of this proposed rule, EPA estimates that these controls for glass furnaces and cement kilns would take at least 2 years to install on a sector-wide basis across the 12-state region; therefore, based on the information available, EPA proposes that the 2023 ozone season is the earliest ozone season by which these non-EGU controls could likely be installed.

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, EPA applied the multi-factor test to EGUs and non-EGUs separately, considering for each the relationship of cost, available emission reductions, and downwind air quality impacts. Specifically, EPA determined the appropriate level of uniform NOX control stringency that addresses the impacts of interstate transport on downwind nonattainment or maintenance receptors. EPA also evaluated possible over-control by determining 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, EPA examined the impacts of each EGU cost threshold identified in section VII.C.1 on the air quality at downwind receptors. Specifically, EPA identified the projected air quality improvement relative to the base case, as well as whether the air quality improvements are sufficient to shift the status of receptors from nonattainment to maintenance or from maintenance to clean. Combining these air quality factors, cost, and emission reductions, EPA identified a control strategy for EGUs at a stringency level that maximizes cost-effective emission reductions. This control strategy reflects the optimization of existing SCR controls and installation of state-of-the-art NOX combustion controls, with an estimated marginal cost of $1,600 per ton. EPA's evaluation also shows that emission budgets reflecting the $1,600 per ton cost threshold do not over-control upwind states' emissions relative to either the downwind air quality problems to which they are linked at step 1 or the 1 percent contribution threshold that triggers further evaluation at step 2 of the 4-step framework for the 2008 ozone NAAQS. To assess downwind air quality impacts for each nonattainment and maintenance receptor identified in section VI.C, EPA evaluated the air quality change at that receptor expected from the progressively more stringent upwind EGU control stringencies that Start Printed Page 69001were available for that time period. This assessment provides the downwind ozone improvements for consideration and provides air quality data that is used to evaluate potential over-control.

To assess the air quality impacts of the various control stringencies, EPA evaluated changes resulting from the application of the emissions reductions at the cost thresholds to states that are linked to each receptor as well as the state containing the receptor. By applying the cost threshold to the state containing the receptor, EPA assumes that the downwind state will implement (if it has not already) an emissions control strategy for their sources that is of the same stringency as the upwind control strategy identified here. Consequently, EPA explicitly ensures that it is accounting for the downwind state's fair share (which is a part of the overcontrol evaluation).[130]

For states that were not linked to that receptor, the air quality change at that receptor was evaluated assuming emissions equal to the engineering analytics base case emission level. This method holds each upwind state responsible for its fair share of the specific downwind problems to which it is linked. For states that are not linked to that receptor (even if they are linked to a different receptor), EPA assumes that they are not making emission reductions beyond those in the base case to that receptor. In practice, because these states, by definition, do not impact such receptors above the contribution threshold, the changes in emissions have little to no effect on the non-linked receptor. Furthermore, if EPA were to explicitly consider these reductions within the framework, it would introduce interdependency into the solution for significant contribution. The state-and-receptor-specific definition of significant contribution would devolve into a simultaneous regional action, where particular states would have to either “go first” or where non-linked states would shoulder burdens to receptors to which they are not linked while other linked states would do less. In any case, EPA has verified that even if it were to account for non-linked state reductions under the selected control stringency, the changes in concentrations at the receptors are so small that they do not affect the attainment or maintenance status of any receptor.

For this assessment, EPA used an ozone air quality assessment tool (ozone AQAT) to estimate downwind changes in ozone concentrations related to upwind changes in emission levels. EPA used this tool to analyze the years for which downwind nonattainment and maintenance problems persist for the 2008 ozone NAAQS. Under the base case, EPA projects that such air quality problems persist through 2025. Therefore, EPA focused its assessment on the years 2021 through 2025.

This tool is similar to the AQAT tool used in the CSAPR Update to evaluate changes in ozone concentrations. The ozone AQAT uses simplifying assumptions regarding the relationship between each state's change in NOX emissions and the corresponding change in ozone concentrations at nonattainment and maintenance receptors to which that state is linked. This method is calibrated using two CAMx air quality modeling scenarios that fully account for the non-linear relationship between emissions and air quality associated with atmospheric chemistry. The two CAMx modeling scenarios are the 2016 base year and the 2023 fh1 future year scenarios for the 2021 time period. For the 2024 and 2025 AQAT simulations, the two CAMx modeling scenarios are the 2023 fh1 future year and the 2028 fh1 scenario. See the Ozone Transport Policy Analysis Proposed Rule TSD for additional details.

For each EGU cost threshold, EPA first evaluated the magnitude of the change in ozone concentrations at the nonattainment and maintenance receptors for each relevant year. EPA next evaluated whether the estimated change in concentration would resolve the receptor's nonattainment or maintenance concern by lowering the average or maximum design values below 76 ppb, respectively. For a complete set of estimates, see the Ozone Transport Policy Analysis Proposed Rule TSD or the ozone AQAT excel file.

In 2021, there are two nonattainment receptors and two maintenance receptors (see section VI.C for details). EPA evaluated the air quality improvements at the four receptors at the two EGU cost threshold levels that are available in the near-term (i.e., $1,600 per ton and $3,900 per ton).[131] EPA found that the average air quality improvement at the four receptors relative to the engineering analytics base case was 0.19 ppb at $1,600 per ton and 0.23 ppb at $3,900 per ton (see Table VII.D.1-2). EPA found that the Westport receptor (090019003) remains nonattainment at all cost levels, the Stratford receptor (090013007) switches from nonattainment to maintenance at $1,600 per ton (i.e., its average DV becomes clean but its maximum DV remains above the NAAQS), while the Houston receptor (482010024) remains maintenance at all levels. Lastly, the New Haven receptor has all nonattainment and maintenance resolved in the engineering analytics base case. 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.

Table VII.D.1-1—Air Quality at the Four Receptors in 2021 at Various Cost Thresholds

Monitor ID No.StateCountyBaseline$1,600/ton$3,900/tonBaseline$1,600/ton$3,900/ton
Average DV (ppb)Average DV (ppb)Average DV (ppb)Max DV (ppb)Max DV (ppb)Max DV (ppb)
90013007ConnecticutFairfield76.1075.8875.8677.0276.8076.78
90019003ConnecticutFairfield78.2678.0878.0678.5678.3978.37
90099002ConnecticutNew Haven73.5673.3273.2975.7275.4775.44
482010024TexasHarris75.6175.4975.3977.2577.1277.02
Average AQ Improvement Relative to Base (ppb)0.000.190.23
Start Printed Page 69002

Figure 1 illustrates the air quality improvement relative to the marginal cost per control technology for the controls associated with the near-term cost thresholds of $1,600 per ton and $3,900 per ton. EPA combines costs, EGU NOX reductions, and corresponding improvements in downwind ozone concentrations, which results in a “knee-in-the-curve” graph, with the “knee” at a point where emission budgets reflect a control stringency with an estimated marginal cost of $1,600 per ton. This level of stringency in emission budgets represents the level at which incremental EGU NOX reduction potential and corresponding downwind ozone air quality improvements are maximized with respect to marginal cost. That is, the ratio of emission reductions to marginal cost and the ratio of ozone improvements to marginal cost are maximized relative to the other emission budget levels evaluated. The more stringent emission budget levels (e.g., emission budgets reflecting $3,900 per ton or greater) yield fewer additional emission reductions and fewer air quality improvements relative to the increase in control costs. This evaluation shows that EGU NOX reductions are available at reasonable cost and that these reductions can provide improvements in downwind ozone concentrations at the identified nonattainment and maintenance receptors.

EPA proposes that the $1,600 per ton level control strategy, associated with optimizing existing SCRs and ensuring that state of the art combustion controls have been fully installed or upgraded, is a relatively highly cost-effective level of control (reflected as being the “knee-in-the-curve”), and should therefore be required to address significant contribution in the 12 linked states. EPA observes this $1,600 per ton level of stringency results in a substantial number of emissions reductions totaling nearly 23,000 tons (19 percent of the baseline level), resulting in all downwind air quality problems for the 2008 ozone NAAQS being resolved after 2024 (one year earlier than the base case). There are also projected changes in receptor status (from projected nonattainment to maintenance-only) for the Stratford and Westport receptors (the first in 2021, the second in 2024). In addition, the Houston receptor changes from maintenance to attainment in 2023. In 2021, the average level of improvement in ozone concentrations at all four of the receptors is 0.19 ppb.

By comparison, the next, more stringent mitigation technology available in 2021 (i.e., SNCR optimization at $3,900 per ton) yields incremental emission reductions of approximately only 3,000 tons. This has a much smaller average air quality improvement of just 0.04 ppb in 2021. Further, this smaller benefit comes at a substantial increase in marginal costs. Moreover, analysis using the AQAT tool suggests this strategy had no further impact on receptors' status. EPA examined the total number of SNCR-controlled coal units in the 12 linked states. A small portion of the coal fleet had this technology in place (14 percent), and of that small portion, the majority of the units with these SNCR controls had emission rates of 0.13 lb/mmBtu or less (many operating less than 0.1 lb/mmBtu), suggesting they were already optimizing their SNCRs. Given the small portion of the coal fleet covered by this technology in the 12 linked states, combined with the Start Printed Page 69003relatively low emission rate on average suggesting ongoing control operation, EPA observed few additional reductions. Given the cost, available reductions, and corresponding air quality improvement, EPA proposes to determine that the potential emission reductions associated with a control strategy of optimizing existing SNCR are not required to eliminate significant contribution from the 12 linked states under the 2008 ozone NAAQS.

Controls associated with the above strategies are implementable by the 2021 ozone season (or in the case of upgraded or new combustion controls, by the 2022 ozone season; see the discussion in section VII.C and in the NOX Mitigation Strategies TSD for details). Thus, as to the 2021 and 2022 ozone seasons these are the only control strategies for EGUs that EPA is assessing for this timeframe because they are the only ones that are possible. See Wisconsin, 938 F.3d at 320.

As discussed above in Section VII.C, EPA estimates that the time necessary to install new SNCR or new SCR controls (represented by $5,800 per ton and $9,600 per ton) on a regional basis across multiple EGUs is approximately 39 to 48 months. While a single new SNCR may be installed within 16 months, for the reasons explained in Section VII.C, a time frame that encompasses the ability for a unit to make a unit-specific choice of what post-combustion control (SCR or SNCR) is best for its configuration and future operating plans is appropriate. Therefore, the timing estimate for SNCR and SCR is considered together and the 39-48 month time frame for SCR installation is the most appropriate time period to use for assessing post-combustion controls. Assuming a final rule in the spring of 2021, this means that these controls could not be operational prior to the 2024 ozone-season, and therefore the reduction potential is not available until the 2025 ozone season. According to EPA's air quality assessment, there are no remaining air quality receptors in 2025 assuming a $1,600 per ton control strategy for EGUs is already in place in the 12 linked states. Therefore, it is not necessary to require emission controls that can only be operational at a point in time when EPA's projections demonstrate there is no remaining interstate transport problem.

EPA is requesting comment on this proposal's determination that new post-combustion controls (SCR or SNCR) are not possible to implement on a regional basis by the start of the 2024 ozone season (Comment C-8). In the event that updated analysis, either via public comments or other information, shows that post-combustion controls may be possible across multiple EGUs on a regional basis before the 2024 ozone season, EPA requests comment on whether the emission reduction potential of new post-combustion controls (SCR or SNCR) at EGUs, on a regional basis, may constitute significant contribution to nonattainment and/or interference with maintenance (Comment C-9). EPA anticipates that such analysis would be applied to the foreseeable circumstances of downwind receptors under the 2008 ozone NAAQS and would require assessment under the multi-factor test set forth in this section (as applied to other emission control strategies). This includes an analysis of cost, emission reduction potential, and downwind air quality impacts. EPA also believes that the degree of nonattainment or maintenance problem anticipated at downwind receptors at the time such controls are purported possible would be a relevant consideration.

2. Non-EGU Assessment

The Agency used CoST and the 2023 projected inventory to identify uncontrolled emissions sources or units and applied controls to emissions units with 150 tpy or more of pre-control NOX emissions, which is an emissions threshold comparable to 25 MW for EGUs. EPA categorized the CoST results by the control technologies, calculated a weighted average cost per ton (in 2016$) for emissions reductions associated with each technology, and identified two tranches of potential reductions based on estimated cost effectiveness (for details see Section VII.B.2). EPA took a series of steps to further verify and refine the NOX emission reduction potential estimated by CoST, the CMDb, and the 2023 projected inventory and found that the cost-effective emissions reductions in tranche one were from SCR applied to glass furnaces and SNCR applied to cement kilns. These controls could likely take 2-4 years to install; therefore, at the time of this proposal, EPA does not believe these non-EGU controls can be installed prior to the 2023 ozone season (for details see Section VII.C.2).

Using 2023 as the potential earliest date by which controls for glass furnaces and cement kilns can be installed, EPA assessed whether these emission reduction strategies should be required at Step 3 under its multi-factor test. First, the Agency extended the findings for glass furnaces and cement kilns from the five states for which the Agency refined the data—Pennsylvania, New York, Ohio, Indiana, and West Virginia—to the five other states linked to an air quality receptor in 2023—Michigan, Illinois, Kentucky, Virginia, and Maryland.[132] For the other five states, because the Agency was not able to verify the existing control information or refine the emission reduction potential through the online permit and trade literature review in the time available, the Agency conservatively assumed that all of the CoST-estimated emissions reductions were real emissions reductions. Combining the results from the refined assessment for five states with the assumption that all of the reductions from the other five states are real emissions reductions, EPA estimated that across the 11 states linked to the remaining receptor in Connecticut in 2023 (Westport), the available emissions reductions from tranche one at less than $2,000 per ton are 1,567 ozone season tons.[133] Using AQAT, EPA assessed whether this level of emissions reductions would have a meaningful effect on the Connecticut receptor. EPA found that the total improvement in air quality from these emissions reductions is 0.03 ppb. This potential air quality improvement is an order of magnitude less than the air quality improvement EPA expects to obtain from the comparable $1,600 per ton control strategy for EGUs in 2023, which is estimated to improve air quality at the remaining Connecticut receptor by 0.30 ppb. Based on this assessment, then the Agency proposes under the multi-factor test that even the potentially most cost-effective reductions from non-EGU sources (i.e., those below $2,000 per ton in tranche one) do not rise to the level of “significance” that would justify mandating them under the good neighbor provision for the 2008 ozone NAAQS. As discussed in more detail in its request for comments below, because of EPA's relatively incomplete and Start Printed Page 69004uncertain datasets on which it based this proposed analysis, EPA encourages stakeholder comments on the analysis and proposed conclusion with respect to the tranche one non-EGU control strategies (Comment C-10).

Turning to tranche two, EPA believes the amount of time needed to install controls or retrofit the 111 non-EGU emissions units identified in tranche two likely extends beyond the 2021 Serious area attainment date; therefore, similar to tranche one, EPA assumes the installation times are no earlier than the 2023 ozone season. In tranche two, the weighted average cost of the estimated emissions reductions from non-EGU emissions sources ranges from $5,000 to $6,600 per ton. In the 11 linked states, the Agency identified approximately 11,100 tons of potential ozone season emissions reductions by applying layered combustion, NSCR (non-selective catalytic reduction) or layered combustion, and ultra-low NOX burners in combination with SCR to 111 emissions units in the oil and gas industry and several manufacturing industries. EPA did not further verify and refine these estimated emissions reductions and believes the estimate of available emission reductions could be lower because the inventory can be missing information on controls on existing emissions sources and CoST may be applying controls to already controlled sources. In Section VII.D.2.a below, EPA seeks comment on the feasibility of further controlling NOX from IC engines and large ICI boilers, including optimizing combustion and installing ultra-low NOX burners.

EPA's assessment is that, with the proposed control strategy for EGUs in place (see section VII.D.1.), there will no longer be any downwind receptors in 2025 with respect to the 2008 ozone NAAQS. Focusing then on whether there are any non-EGU NOX emissions reductions available to address significant contribution under the Step 3 multi-factor test in either the 2023 or 2024 ozone seasons, based on its assessment EPA proposes to conclude that any such potentially available reductions would not be justified. EPA's proposed assessment is that there is a relatively smaller quantity of NOX reductions that may be available from the non-EGU control strategies in tranches one and two in these years, across the 11 states linked to the remaining receptor. These control strategies are estimated to have a limited impact on further improving air quality at this receptor. As shown in the Ozone Policy Analysis TSD, the incremental effects of emission reductions from non-EGUs do not affect the status of any of the four receptors in any of the relevant years compared with the $1,600 per ton EGU policy scenario. For more information, refer to the Ozone Transport Policy Analysis Proposed Rule TSD. EPA therefore proposes to conclude that no emission reductions from non-EGU sources are necessary to eliminate significant contribution under the good neighbor provision for the 2008 ozone NAAQS.

a. Request for Comment on Non-EGU Control Strategies and Measures

Recognizing the limitations and uncertainties in the existing data on which EPA bases this proposal, EPA is requesting comment to assist in substantiating whether this assessment is fully supportable based on additional information and analyses not currently available to the Agency (Comment C-11). To develop a more complete record, EPA requests comment on a number of questions related to specific control strategies the Agency evaluated, and in particular seeks feedback and data from stakeholders with relevant expertise or knowledge. Should such additional information and analyses show that emissions reductions from non-EGU sources in the linked upwind states would be more cost-effective than what is included in EPA's current assessment, available for installation earlier than EPA estimates, or more impactful on downwind air quality than EPA's current information suggests, then the Agency remains open to the possibility of finalizing a rule requiring such controls as may be justified under the Step 3 multi-factor test.

EPA understands that the methodology employed was one approach to assessing emission reduction potential from non-EGU emissions sources or units and to determining an appropriate stringency level for non-EGU sources. In the time available, the Agency was not able to employ another methodology or conduct another assessment of other potential non-EGU control strategies or measures and verify the estimated emissions reductions in the same manner as it did for some of the tranche one states.

As indicated in Section VII.C.2 above, information about existing controls on non-EGU emissions sources in the inventory was missing for some states and incomplete for some sources. The approach EPA used in this proposal was to assess emission reduction potential using CoST and the projected 2023 inventory to identify emissions units that were uncontrolled. Given that EPA's assessment of any other NOX control strategies would also rely on CoST, the CMDb, and the inventory to identify emissions units that were uncontrolled and to assess emission reduction potential from non-EGU sources, the Agency believes such an assessment would likely lead to a similar conclusion that estimated emission reduction potential is uncertain.

As such, for this and future regulatory efforts, to improve the underlying data used in an assessment of emission reduction potential from non-EGU sources, EPA requests comments on: (i) The existing assessment of emission reduction potential from glass furnaces and cement kilns (Comment C-12); (ii) emission reduction potential from other control strategies or measures on a variety of emissions sources in several industry sectors (Comment C-13); and (iii) the feasibility of further controlling NOX from IC engines and large ICI boilers, including optimizing combustion and installing ultra-low NOX burners (Comment C-14). The three sections below introduce the areas for comment and describe workbooks generated by CoST, the CMDb, and the 2023 projected inventory with the underlying data to review for comment.

First, EPA requests comment on the aspects of the assessment presented above of emission reduction potential from the glass and cement manufacturing sectors (Comment C-15). To help inform review and comments, please see the following Excel workbooks available in the docket and referenced in the memorandum titled Assessing Non-EGU Emission Reduction Potential: (i) For a summary of the CoST run results CoST Control Strategy—Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling—No Replace—07-23-2020, and (ii) for summaries of emissions reductions by control technologies, Control Summary—Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling—No Replace—05-18-2020. Note that the CoST Control Strategy—Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling—No Replace—07-23-2020 Excel workbook includes a READ ME worksheet that provides details on the parameters used for the CoST run.

Specifically, EPA is soliciting comment on the following:

  • Are applying SCR to uncontrolled or under-controlled glass furnaces and SNCR to uncontrolled or under-controlled cement kilns in the linked states feasible approaches to achieve cost-effective emissions reductions? If not, what types of cost-effective controls can be applied to these sources?
  • Does EPA have the right and most up to date information on emissions and Start Printed Page 69005existing control technologies for the units included in this assessment? If not, what is the correct and more up to date information?
  • After looking at the underlying CoST run results, are the cost estimates accurate and reasonable? If not, what are more accurate cost estimates?
  • What is the earliest possible installation time for SCR on glass furnaces?
  • What is the earliest possible installation time for SNCR on cement kilns?
  • For the non-EGU facilities without any emissions monitors, what would CEMS cost to install and operate? How long would CEMS take to program and install?

In addition to the assessment of emission reduction potential from the glass and cement manufacturing sectors, for the 12 linked states EPA attempted to summarize all potential control measures for emissions units with 150 tpy or more pre-control NOX emissions in 2023 in several industry sectors. This information illustrates that there are many potential approaches to assessing emissions reductions from non-EGU emissions sources or units. EPA used the Least Cost Control Measure worksheet from a CoST run.[134] By state for the 12 linked states and then by facility, this information is summarized in the Excel workbook titled CoST Control Possibilities $10k 150 tpy cutoff 12 States Updated Modeling—06-30-2020, also available in the docket and referenced in the memorandum titled Assessing Non-EGU Emission Reduction Potential.

Second, specifically EPA requests comment (Comment C-16) on the following:

  • Other than glass and cement manufacturing, are there other sectors or sources that could achieve potentially cost-effective emissions reductions? What are those sectors or sources? What control technologies achieve the reductions? What are cost estimates and installation times for those control technologies?
  • Are there other sectors where cost effective emission reductions could be obtained by, in lieu of installing controls, replacing older, higher emitting equipment with newer equipment?
  • Are there sectors or sources where cost effective emission reductions could be obtained by switching from coal-fired units to natural gas-fired units?
  • For non-EGU sources without emissions monitors, what would CEMS cost to install and operate? How long would CEMS take to program and install? Are monitoring techniques other than CEMS, such as predictive emissions monitoring systems (PEMS), sufficient for certain non-EGU facilities that would not be brought into a trading program? If so, for what types of non-EGU facilities, and under what circumstances, would PEMS be sufficient? What would be the cost to install and operate monitoring techniques other than CEMS?

Third, in the workbook titled CoST Control Possibilities $10k 150 tpy cutoff 12 States Updated Modeling—06-30-2020 EPA included two worksheets with information on controls for ICI boilers and IC engines: (i) Boilers—ULNB and (ii) IC Engines—LEC. For the 12 linked states, EPA summarized CoST's application of ultra-low NOX burners (ULNB) on ICI boilers and low emission combustion (LEC) on IC engines. Assuming that the estimated emissions reductions from the application of these controls are real and cost-effective, there could be approximately 5,000 ozone season tons of emissions reductions from 52 ICI boilers and 8,000 ozone season tons of emissions reductions from 69 IC engines. This information is summarized in Table VII.D.2-1 below.

Table VII.D.2-1—Summary of Potential Emissions Reductions From ULNB on ICI Boilers and LEC on IC Engines

ICI boilersIC engines
Number of Emissions Units in the 12 Linked States5269
2023 Projected Total NOX Emissions in the 12 Linked States (ozone season tons, reflects any existing control before ULNB or LEC were applied)6,7799,260
2023 Projected Total NOX Emissions in the 12 Linked States after Applying ULNB to Boilers (ozone season tons)1,695
2023 Projected Total NOX Emissions in the 12 Linked States after Applying LEC to IC Engines (ozone season tons)1,231
Number of Units with No Known Existing Control5157

EPA is requesting comments on the feasibility of further controlling NOX from large ICI boilers and IC engines, including optimizing combustion and installing low NOX burners (Comment C-17). As mentioned in the discussion above on emissions reductions from the EGU sector, EPA understands that it is generally possible to install LNB on EGU boilers fairly quickly and that these burners can significantly reduce NOX emissions. EPA notes that in the original interstate transport rule, the NOX SIP call, the Agency concluded that controls on large, non-EGU boilers and turbines were cost effective and allowed states to include those emissions sources in their budgets as a means of providing additional opportunities to reduce state-wide NOX emissions in a cost-effective manner.[135] Therefore, the Agency solicits comment on whether EPA should require that large non-EGU boilers and turbines—as defined in the NOX SIP call as boilers and turbines with heat inputs greater than 250 Million British Thermal Units (mmBtu) per hour or with NOX emissions greater than 1 ton per ozone season day [136] —within the 12 states employ controls that achieve emissions reductions greater than or equal to what can be achieved through the installation of low NOX burners (Comment C-18).

Also, five of the 12 states that are subject to this rulemaking are also within the Ozone Transport Region (OTR)—Maryland, New Jersey, New York, Pennsylvania, and Virginia. As member states of the OTR, these five states are required to implement reasonably available control technology Start Printed Page 69006(RACT) state-wide on major sources of emissions.[137] It is likely that NOX controls, such as low NOX burners, are already in wide-spread use within these five states. However, such controls may not be as widely used in states outside of the OTR. Therefore, the Agency also solicits comment on (i) the magnitude of the emissions reductions that could be achieved by requiring that large non-EGU boilers and turbines install controls that achieve emissions reductions greater than or equal to what could be achieved through the installation of low NOX burners, (ii) the prevalence of these or better NOX controls already in place on this equipment in these 12 states, and (iii) the time it typically takes to install such controls (Comment C-19).

In addition to the above, EPA is requesting comments on the following:

  • How effective are ultra-low NOX burners or low NOX burners in controlling NOX emissions from ICI boilers?
  • Are they generally considered part of the process or add-on controls? If they are part of a process, how could EPA estimate the cost associated with changing the process to accommodate ultra-low NOX burners and low NOX burners?
  • What are the costs (capital and annual) for these as add-on control technologies on ICI boilers?
  • What are the earliest possible installation times for these control technologies on ICI boilers? EPA believes it is generally possible to install low NOX burners on EGU boilers relatively quickly and that low NOX burners can significantly reduce NOX emissions. EPA solicits comment on whether this is also true for large non-EGU ICI boilers.
  • Do some of the emissions units included in the summary already have either add-on controls or controls that are part of a process? If so, what control is on the unit and what is the control device (or removal) efficiency?
  • Natural gas compressor stations are the largest NOX-emitting non-EGU sector [138] affecting the 12 states that are the subject of this proposal, and many of these facilities are powered by decades-old, uncontrolled IC engines. Should emissions reductions be sought from the IC engines at these stations, either through installing controls, upgrading equipment, or other means?
  • How effective is low emission combustion in controlling NOX from IC engines?
  • What is the cost (capital and annual) for low emission combustion on IC engines?
  • What is the earliest possible installation time for low emission combustion on IC engines? In lieu of installing controls, is replacing older, higher emitting equipment with newer equipment a cost-effective way to reduce emissions from IC engines?
  • Do some of the emissions units included in the summary already have either add-on controls or controls that are part of a process? If so, what control is on the unit and what is the control device (or removal) efficiency?

EPA welcomes comments providing data and information on all of the above requests (Comment C-20). The Agency encourages stakeholders with particular expertise, such as source owners and operators, state agencies, trade associations, and knowledgeable non-governmental organizations, to evaluate the information available in the docket and presented above and provide updates, corrections, and other information as may assist in improving EPA's ability to more accurately assess non-EGU emission control strategies relevant to addressing interstate ozone transport.

3. Overcontrol Analysis

As part of the air quality analysis using the Ozone AQAT, 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 NAAQS; 0.75 ppb).

In EME Homer City, the Supreme Court held that 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 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 emission limits. Some of those upwind States may still be subject to the more stringent emissions limits so as not to cause other downwind locations to which those States are linked to fall into nonattainment.” Id. at 14-15. As the Supreme Court explained, “while EPA has a statutory duty to avoid over-control, the Agency also has a statutory obligation to avoid `under-control,' i.e., to maximize achievement of attainment downwind.” 572 U.S. at 523. The Court noted that “a degree of imprecision is inevitable in tackling the problem of interstate air pollution” and that incidental over-control may be unavoidable. Id. “Required to balance the possibilities of under-control and over-control, EPA must have leeway in fulfilling its statutory mandate.” Id.[139]

Consistent with these instructions from the Supreme Court and the D.C. Circuit, EPA first evaluated whether reductions resulting from the proposed $1,600 per ton emission budgets for EGUs in 2021 and 2022 can be anticipated to resolve any downwind nonattainment or maintenance problems. This assessment shows that the emission budgets reflecting $1,600 per ton would change the status of one of the two nonattainment receptors (first shifting the Stratford monitor to a maintenance-only receptor in 2021 and then shifting that monitor to attainment in 2022). However, no other nonattainment or maintenance problems would be resolved in 2021 or 2022. EPA's assessment shows that none of the 11 states are solely linked to the Stratford receptor that is resolved at the $1,600 per ton level of control stringency in 2022.

Reductions resulting from the $1,600 per ton emission budgets for EGUs would shift the Houston receptor in Harris County, Texas, from maintenance to attainment in 2023. These emission reductions would also shift the last remaining nonattainment receptor (the Westport receptor in Fairfield, Connecticut) to a maintenance-only receptor in 2024. No nonattainment or maintenance receptors would remain after 2024.

Next, EPA evaluated the potential for over-control with respect to the 1 percent of the NAAQS threshold applied in this proposed rulemaking at Start Printed Page 69007step 2 of the good neighbor framework for the $1,600 per ton cost threshold level for each year downwind nonattainment and maintenance problems persist (i.e., 2021 through 2024). Specifically, EPA evaluated whether the emission levels would reduce upwind EGU emissions to a level where the contribution from any of the 12 upwind states would be below the 1 percent threshold that linked the upwind state to the downwind receptors. EPA finds that under the $1,600 per ton EGU cost threshold level for 2021 to 2024 emission levels, all 12 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. For more information about this assessment, refer to the Ozone Transport Policy Analysis Proposed Rule TSD and the Ozone AQAT.

Since emission reductions resulting from the proposed $1,600 per ton emission budgets for EGUs are not projected to result in the expected ozone improvements (1) being 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) reducing the upwind state's ozone contributions below the screening threshold (i.e., 1 percent of the NAAQS; 0.75 ppb), EPA concludes that the $1,600 control strategy does not result in overcontrol.

Based on the multi-factor test applied to both EGU and non-EGU sources and subsequent assessment of overcontrol, EPA proposes to determine that the emission reductions associated with the $1,600 per ton control stringency for EGUs constitute elimination of significant contribution from the 12 linked upwind states. Therefore, as discussed in section VIII, EPA proposes to establish emission budgets for EGUs in the 12 linked states that reflect the remaining allowable emissions after the emissions reductions associated with the $1,600 per ton control stringency have been achieved.

VIII. Implementation of Emissions Reductions

A. Regulatory Requirements for EGUs

The CSAPR established a NOX ozone season trading program for states determined in that rulemaking to have good neighbor obligations with respect to the 1997 ozone NAAQS. The CSAPR Update established a new NOX ozone season trading program for 22 states determined to have good neighbor obligations with respect to the 2008 ozone NAAQS—the CSAPR NOX Ozone Season Group 2 Trading Program—and renamed the NOX ozone season trading program established in the CSAPR, which now covers only Georgia, the CSAPR NOX Ozone Season Group 1 Trading Program.[140] Each of these NOX ozone season trading programs established state-level budgets for EGUs and allowed affected sources within each state to use, trade, or bank allowances within the same trading group for compliance. In the CSAPR NOX Ozone Season Group 1 and Group 2 trading programs, sources are required to retire one Group 1 or Group 2 allowance, respectively, for each ton of NOX emitted during a given ozone season. EPA is proposing to use the same regional trading approach, with modifications to reflect updated budgets, trading groups, and certain additional revisions, as the compliance remedy implemented through the FIPs to address interstate transport for the states having further good neighbor obligations with respect to the 2008 ozone NAAQS in this rule.

Of the 22 states currently covered by the CSAPR NOX Ozone Season Group 2 Trading Program, EPA is proposing to establish revised budgets for 12 states, as explained below. Therefore, EPA is proposing the creation of an additional geographic group and trading program comprised of these 12 upwind states with remaining linkages to downwind air quality problems in 2021. This new group, Group 3, will be covered by a new CSAPR NOx Ozone Season Group 3 Trading Program. Aside from the removal of the 12 covered states from the current Group 2 program, this proposal leaves unchanged the budget stringency and geography of the existing CSAPR NOX Ozone Season Group 1 and Group 2 trading programs.

EPA is proposing to use the existing CSAPR NOX ozone season allowance trading system framework, established in the CSAPR for Group 1 and used again in the CSAPR Update for Group 2, to implement the emission reductions identified and quantified in the FIPs for this proposal. The new Group 3 trading program is proposed to be codified at 40 CFR part 97, subpart GGGGG. As with the existing CSAPR trading programs, emissions monitoring and reporting would be performed according to the provisions of 40 CFR part 75, and decisions of the Administrator under the program would be subject to the administrative appeal procedures in 40 CFR part 78.

B. Quantifying State Emissions Budgets

EPA is proposing to quantify state emission budgets consistent with the approach used in the CSAPR Update. However, given Wisconsin's direction to implement a full remedy, EPA must now address upwind emission reduction potential beyond the initial year for which it is establishing emission budgets. Whereas in the partial-remedy context of the CSAPR Update, EPA only established budgets based on its assessment of the 2017 analytic year and noted it would revisit future years at a later date, in this action EPA is simultaneously looking at budgets for all relevant future years to comply with the full-remedy directive. Consequently, for the Group 3 states EPA is proposing to quantify specific budgets in each year to ensure that EGUs continue to be incentivized to implement the full extent of EPA's selected control strategy while nonattainment and maintenance concerns at the linked downwind receptors remain unresolved. In effect, by doing this, EPA will be accounting for scheduled fleet turnover after the first-year budget. For instance, if State X's budget was 100 tons in 2021, but there are 10 tons of emissions from a unit scheduled to retire at the end of the year and 5 tons expected from a new unit coming online, then the state emission budget for 2022 would reflect these scheduled changes by establishing a budget of 100 tons—(10 tons -5 tons) = 95 tons for the subsequent year. This adjustment in methodology reflects the need to anticipate and respond to scheduled fleet turnover in the power sector in ensuring that the control strategy selected to eliminate significant contribution remains incentivized. Based on the Agency's experience implementing prior good neighbor trading programs, emissions budgets that do not account for planned retirements in subsequent years lead to an erosion in the allowance price signal and hence a reduced incentive to take the mitigation measures identified in EPA's significant contribution determination (e.g., optimize SCRs). EPA's air quality projections demonstrate that even with a $1,600 per ton EGU strategy, the Group 3 states continue to contribute above the 1 Start Printed Page 69008percent of the NAAQS threshold to at least one receptor whose nonattainment and maintenance concerns persist through the 2024 ozone season (with the exception of Louisiana, as discussed in more detail below). As such, and in order to implement a full remedy as required under the Wisconsin decision, EPA proposes that it is necessary to design a Step 4 implementation framework that will effectively ensure the continued optimization of existing SCR and the incentive to install or upgrade combustion controls for so long as downwind nonattainment and maintenance concerns persist. Therefore, for all Group 3 states except Louisiana, the emission budget setting process described below applies to each year from 2021 through 2024, with the budgets held constant from 2024 onwards. For Louisiana, the emission budget setting process applies to 2021 and 2022 only, with the budget held constant from 2022 onwards, as the Houston receptor is resolved in 2023.

EPA is not proposing to increase the stringency of the program over these years in the sense of requiring any further emissions reductions than the control strategy represented by $1600 per ton achieves. Rather, these budget adjustments account for pre-existing, on-going changes in the EGU sector, which if not accounted for, could significantly weaken the incentive to optimize existing SCR and install or upgrade combustion controls. By determining emissions budgets for a given mitigation technology across a range of years (e.g., 2021-2024), EPA is able to best reflect the realization of that mitigation strategy in any given year. For instance, a unit may be scheduled to retire (independent of any environmental regulation) in 2023. Therefore, the same $1,600 per ton uniform technology scenario (i.e., SCR optimization and combustion control installation or upgrade) will produce a different state emissions level (i.e., budget) in 2021 and 2024 due to this change in fleet composition. Having the emissions estimated for each year allows EPA to best ensure the reductions available from the identified control strategy continue to be achieved to eliminate that state's significant contribution. This type of phased implementation preserves the intended control stringency of the rule and is consistent with the direction under the Wisconsin decision to promulgate a full-remedy rule. In prior trading programs, stakeholders have observed that the program's static emission budgets quickly fell behind the rapid pace of change in the power sector fleet. As this occurs, a large allowance bank builds and the price of allowances falls below the price in the initial years. For example, CSAPR Update Group 2 allowances started out at levels near $800 per ton in 2017 and provided a strong signal for the mitigation technology identified in the significant contribution determination. However, in subsequent years as the fleet of covered EGUs changed, the price of those allowances declined to less than $70 per ton in July 2020.[141] Stakeholders have pointed out that these low prices could allow for some backsliding of the mitigation technologies (e.g., reduced incentive to operate a SCR) that were initially determined to be cost-effective and required to eliminate significant contribution. At the same time that the incentive for EPA's selected control strategy weakens, EPA's data shows that downwind air quality receptors continue to persist at Step 1, and the overall level of anthropogenic emissions from an upwind state continues to contribute to those receptors above the contribution threshold at Step 2. Under these conditions, a legal basis exists within EPA's 4-step framework to undertake measures that ensure EGUs continue to implement EPA's selected control strategy. Stated differently, EPA is confident that it is well within its statutory authority under CAA section 110(a)(2)(D)(i)(I) to impose on each covered EGU in a linked Upwind state an emission limit that is enforceable and permanent, reflective of the control strategy EPA has determined is needed to eliminate significant contribution from that state. EPA is proposing an approach that better incentivizes the selected control strategy while retaining the flexible compliance benefits of an interstate-trading approach to implementation.[142]

In summary, in response to the Wisconsin court's direction to implement a full remedy, EPA is proposing to implement ozone season budgets for each year that reflect ongoing incentivization of the emission reduction measures identified in this rule, with a final budget being implemented in 2024 (the last year EPA projects downwind receptors to remain unresolved) and then held constant for each year thereafter. EPA requests comment on this approach (Comment C-21).

EPA's proposed 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.

For determining emission budgets, EPA proposes to use historical ozone season data from the most recent year reported (that is, 2019 ozone season data for this proposed rulemaking). This is similar to its approach in the CSAPR Update where EPA began with 2015 data (the most recent year at the time). Like the CSAPR Update methodology, EPA is proposing to combine historical data with IPM data to determine emission budgets. The budget setting process has three primary steps:

(1) Determine a future year baseline—Start with the latest reported historical unit-level data (e.g., 2019), and adjust any unit data where a retirement or new build is known to occur by the baseline year. This results in a future year (e.g., 2021) baseline for emissions budget purposes.[143]

(2) Factor in additional mitigation controls for the selected cost threshold (e.g., $1600 per ton). For the unit-level mitigation technologies identified at this cost level, adjust the baseline unit-level emissions and emission rates. For example, if a SCR-controlled unit had a baseline greater than 0.08 lb/mmBtu, its 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 relative way to capture the reductions expected from generation shifting at a given $ per ton level that reflects control optimization (constrained to within-state shifting).

By using historical unit and state-level NOX emission rates, heat input, and emissions data at step 1 of the budget setting process, EPA is grounding its budgets in the most recent historical operation for the covered units.[144] This data is a reasonable starting point for the budget setting process as it reflects the latest data reported by affected facilities under 40 CFR part 75. The reporting requirements Start Printed Page 69009include 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. In step 1 of the budget setting process, EPA first adjusted the 2019 ozone-season data to reflect committed fleet changes under a baseline scenario (i.e., announced and confirmed retirements, new builds, and retrofits that will, or have already occurred by 2021). For example, if a unit emitted in 2019, but retired in 2020, its 2019 emissions would not be included in the 2021 estimate. For units that had no known changes, the 2021 emissions assumption was the actual reported data from 2019 at this first step of adjusting the baseline. EPA also included known new units and scheduled retrofits in this manner. Using this method, EPA arrived at a baseline emission, heat input, and emission rate estimate for each unit for a future year (e.g., 2021), and then was able to aggregate those unit-level estimates to state-level totals. These state-level totals constituted the state's baseline from an engineering analytics perspective. The ozone-season state-level emissions, heat input, and emissions rates for covered sources under a baseline scenario were determined for each future year examined (2021 through 2024). Because 2024 is the last ozone season that EPA projects continued contribution to any downwind receptors, 2024 is the last year EPA proposes to make an adjustment to emission budgets.

For step two of the emissions budget setting process, EPA examined how the baseline emissions and emission rates would change under different mitigation cost threshold scenarios for EGUs. For instance, under the $1,600 per ton scenario, if a unit was not operating its SCR at 0.08 lb/mmBtu or lower in the baseline, EPA lowered that unit's assumed emission rate to 0.08 lb/mmBtu and calculated the impact on the unit's and state's emission rate and emissions. Note, the heat input is held constant for the unit in the process, reflecting the same level of unit operation compared to historical 2019 data. An improved emission rate is then applied to this heat input, reflecting control optimization. In this manner, the state-level baseline totals from step one reflecting known baseline changes were adjusted to reflect the additional application of the assumed control technology at a given cost threshold.

Finally, at step three of the emissions budget setting process, EPA used IPM to capture any generation shifting at a given cost threshold (e.g., $1,600 per ton) necessary for the respective mitigation technology to operate. EPA explains how it accounts for generation shifting in more detail in in Section VII.B and in the Ozone Transport Policy Analysis TSD. In this rule, as a proxy for the near-term reductions required by 2021, EPA has constrained generation shifting to occur only within-state. As explained in the Ozone Transport Policy Analysis TSD, the degree to which generation shifting affects the budgets is small, accounting for approximately 2 percent of baseline emissions for each year.

EPA requests comment on the proposed approaches described above, as well as alternatives discussed in the budget-setting TSD (Comment C-22). Specifically, EPA requests comment on its consideration of using 2020 data in place of 2019 data as the most recent historical data set to inform final rule budgets. Although the reduction potential associated with the selected control strategy described in section VII would likely not change substantially with that data set, the baseline values calculated in step one of the emissions budget setting process may change significantly and possibly result in lower or higher state-level emission budgets.

C. Elements of Proposed Trading Program

To implement the updated emissions budgets developed according to the process described in section VIII.B., EPA is proposing to require EGUs in each of the 12 covered states to participate in a new CSAPR NOX Ozone Season Group 3 Trading Program. The provisions of the new Group 3 trading program would be largely identical to the provisions of the Group 2 trading program in which all of the covered EGUs currently participate, except for the differences in state budgets and geography established in this rule to address the covered states' remaining obligations under CAA section 110(a)(2)(D)(i)(I) with respect to the 2008 ozone NAAQS. The only other differences between the new Group 3 trading program regulations and the current Group 2 trading program regulations are a small number of proposed corrections and administrative simplifications that have no effect on program stringency; EPA proposes to eliminate these differences by making the same corrections and simplifications to the regulations for the Group 2 trading program and the other existing CSAPR trading programs.[145] In this section, the Agency discusses major elements of the proposed trading program, with emphasis on the elements that differ from the existing provisions of the Group 2 trading program as well as several provisions specifically designed to address the transition from the Group 2 trading program to the Group 3 trading program. EPA requests comment on use of the proposed trading program to implement the emissions reductions that are proposed to be required under this action (Comment C-23).

1. Applicability

In this rule, EPA proposes to use the same EGU applicability provisions in the new Group 3 trading program as it used in the existing Group 2 trading program and the other CSAPR trading programs, without change. Under the general CSAPR applicability provisions, a covered unit is any stationary fossil-fuel-fired boiler or combustion turbine serving at any time on or after January 1, 2005, a generator with nameplate capacity exceeding 25 MW, which is producing electricity for sale, with the exception of certain cogeneration units and solid waste incineration units.

2. State Budgets, Variability Limits, Assurance Levels, and Penalties

EPA is proposing to establish revised state budgets for EGU emissions of ozone season NOX for the 12 “Group 3” states subject to new or amended FIPs in this proposed rule in order to fully address these states' significant contribution with respect to the 2008 ozone NAAQS. The budgets would be established according to the process described in section VIII.B. As discussed in that section, for each of the covered states, separate budgets are proposed for the three individual years 2021, 2022, and 2023, and then for 2024 and beyond.[146] Portions of the updated NOX ozone season emission budgets would be reserved as updated new unit set-asides and Indian country new unit set-asides for the same control periods, as further described in sections VIII.C.3.b. and VIII.C.3.c. The amounts Start Printed Page 69010of the proposed state emissions budgets for 2021, 2022, 2023, and 2024 and beyond are shown in tables VIII.C.2-1, VIII.C.2-2, VIII.C.2-3, and VIII.C.2-4.

The proposed requirement for EGU sources in these states to comply with the budgets established in this rulemaking will replace the existing requirements in these states under the CSAPR NOX Ozone Season Group 2 Trading Program established in the CSAPR Update. For Group 3 states that were found in the CSAPR Update to still have good neighbor obligations with respect to the 1997 ozone NAAQS, EPA proposes that participation in the more stringent Group 3 trading program would satisfy those obligations.[147]

In the CSAPR and the CSAPR Update, EPA developed assurance provisions, including variability limits and assurance levels (with associated compliance penalties), to ensure that each state will meet its pollution control and emission reduction obligations and to accommodate inherent year-to-year variability in state-level EGU operations. Establishing assurance levels with compliance penalties responds to the D.C. Circuit's holding in North Carolina requiring EPA to ensure within the context of an interstate trading program that sources in each state are required to eliminate emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in another state.[148]

The CSAPR Update budgets, and the updated CSAPR emission budgets proposed in this document, reflect EGU operations in an “average year.” However, year-to-year variability in EGU operations occurs due to the interconnected nature of the power sector, changing weather patterns, changes in electricity demand, or disruptions in electricity supply from other units or from the transmission grid. Recognizing this, the trading program provisions finalized in the CSAPR and the CSAPR Update rulemakings include variability limits, which define the amount by which an individual state's emissions may exceed the level of its budget in a given year to account for variability in EGU operations. A state's budget plus its variability limit equals a state's assurance level, which acts as a cap on a state's NOX emissions during a given control period (in this rulemaking, the relevant control period is the May-September ozone season). The new CSAPR NOX Ozone Season Group 3 Trading Program provisions established for affected sources in the 12 states subject to the new trading program under this proposed rule contain equivalent assurance provisions to the prior CSAPR trading programs.

The variability limits ensure that the trading program can accommodate the inherent variability in the power sector while ensuring that each state eliminates the amount of emissions within the state, in a given control period, that must be eliminated to meet the statutory mandate of CAA section 110(a)(2)(D)(i)(I). Moreover, the structure of the trading program, which achieves required emission reductions through limits on the total numbers of allowances allocated, assurance provisions, and penalty mechanisms, ensures that the variability limits only allow the amount of temporal and geographic shifting of emissions that is likely to result from the inherent variability in power generation, and not from decisions to avoid or delay the optimization or installation of necessary controls.

To establish the variability limits in the CSAPR, EPA analyzed historical state-level heat input variability as a proxy for emissions variability, assuming constant emission rates. See 76 FR 48265. The variability limits for ozone season NOX in both the CSAPR and the CSAPR Update were calculated as 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 this proposed rulemaking, EPA is proposing to retain variability limits for the 12 Group 3 states covered by this rule calculated as 21 percent of each state's revised budget.[149]

Table VIII.C.2-1—CSAPR NOX Ozone Season Group 3 State Budgets, Variability Limits, and Assurance Levels for 2021 150

StateEmission budget (tons)Variability limit (tons)Assurance level (tons)
Illinois9,4441,98311,427
Indiana12,5002,62515,125
Kentucky14,3843,02117,405
Louisiana15,4023,23418,636
Maryland1,5223201,842
Michigan12,7272,67315,400
New Jersey1,2532631,516
New York3,1376593,796
Ohio9,6052,01711,622
Pennsylvania8,0761,6969,772
Virginia4,5449545,498
West Virginia13,6862,87416,560
Start Printed Page 69011

Table VIII.C.2-2—CSAPR NOX Ozone Season Group 3 State Budgets, Variability Limits, and Assurance Levels for 2022

StateEmission budget (tons)Variability limit (tons)Assurance level (tons)
Illinois9,4151,97711,392
Indiana11,9982,52014,518
Kentucky11,9362,50714,443
Louisiana14,8713,12317,994
Maryland1,4983151,813
Michigan11,7672,47114,238
New Jersey1,2532631,516
New York3,1376593,796
Ohio9,6762,03211,708
Pennsylvania8,0761,6969,772
Virginia3,6567684,424
West Virginia12,8132,69115,504

Table VIII.C.2-3—CSAPR NOX Ozone Season Group 3 State Budgets, Variability Limits, and Assurance Levels for 2023

StateEmission budget (tons)Variability limit (tons)Assurance level (tons)
Illinois8,3971,76310,160
Indiana11,9982,52014,518
Kentucky11,9362,50714,443
Louisiana14,8713,12317,994
Maryland1,4983151,813
Michigan9,8032,05911,862
New Jersey1,2532631,516
New York3,1376593,796
Ohio9,6762,03211,708
Pennsylvania8,0761,6969,772
Virginia3,6567684,424
West Virginia11,8102,48014,290

Table VIII.C.2-4—CSAPR NOX Ozone Season Group 3 State Budgets, Variability Limits, and Assurance Levels for 2024 and Beyond

StateEmission budget (tons)Variability limit (tons)Assurance level (tons)
Illinois8,3971,76310,160
Indiana9,4471,98411,431
Kentucky11,9362,50714,443
Louisiana14,8713,12317,994
Maryland1,4983151,813
Michigan9,6142,01911,633
New Jersey1,2532631,516
New York3,1196553,774
Ohio9,6762,03211,708
Pennsylvania8,0761,6969,772
Virginia3,3957134,108
West Virginia11,8102,48014,290

The assurance provisions include penalties that are triggered in the event that the covered sources' emissions in a given state, as a whole, exceed the state's assurance level. The CSAPR and the CSAPR Update provided that, when the emissions from EGUs in a state exceed that state's assurance level in a given year, particular sources within that state will be assessed a 3-to-1 allowance surrender on the exceedance of the assurance level. Specifically, each excess ton above a given state's assurance level must be met with one allowance, per standard compliance, and two additional allowances to satisfy the penalty. The penalty was designed to deter state-level emissions from exceeding assurance levels. In both the CSAPR and the CSAPR Update, the assurance provisions were designed to account for variability in the electricity sector while ensuring that the necessary emission reductions occur within each covered state, consistent with the court's holding in North Carolina, 531 F.3d at 908. If EGU emissions in a given state do not exceed that state's assurance level, no penalties are incurred by any source.

To assess the penalty under the assurance provisions, EPA is proposing to follow the same methodology Start Printed Page 69012finalized in the CSAPR Update. See 81 FR 74567. In that methodology, EPA evaluates whether any state's total EGU emissions in a control period exceeded the state's assurance level, and if so, EPA then determines which groups of units in the state represented by a “common designated representative” emitted in excess of the common designated representative's share of the state assurance level and, therefore, will be subject to the allowance surrender requirement described above. Penalties under the assurance provisions are triggered for the group of sources represented by a common designated representative when two conditions are met: (1) The group of sources and units with a common designated representative are located in a state where the total state EGU emissions for a control period exceed the state assurance level; and (2) that group with the common designated representative had emissions exceeding the respective common designated representative's share of the state assurance level. EPA is proposing assurance provisions for the CSAPR NOX Ozone Season Group 3 Trading Program that are equivalent to the assurance provisions in the CSAPR NOx Ozone Season Group 2 Trading Program.

In this action, EPA is proposing minor revisions to the procedures for administering the assurance provisions starting with the 2023 control period [151] for consistency with proposed revisions to the process for allocating allowances from the new unit set-asides that are discussed in section VIII.C.3.b. The same minor revisions are proposed to be implemented in the existing CSAPR trading programs, as discussed in section VIII.C.8. The proposed revisions concern the procedures for determining the portion of the state's assurance level to be assigned to each common designated representative. Specifically, certain provisions of these procedures are designed to address circumstances where a new unit operates but has no allowance allocation determined for it. Administration of these provisions requires EPA to issue a notice to collect information needed solely for this purpose that is not otherwise required to be reported to EPA. Because the revised new unit set-aside (“NUSA”) allocation procedures would eliminate the possibility that a new unit would not have an allowance allocation determined for it, EPA proposes to eliminate the provisions for issuance of the related extra notice starting with the 2023 control period. EPA also proposes to extend the date as of which a common designated representative is determined under both the new Group 3 program and the existing CSAPR programs from April 1 of the year following the control period to July 1 so as to preserve the relationship of those dates to the allowance transfer deadline, which is proposed to be extended from March 1 of the year following the control period to June 1.[152] Further discussion of these changes from the current provisions in the existing trading programs is provided in section VIII.C.8.

EPA requests comment on the proposed state budgets, variability limits, assurance levels, and assurance provisions (Comment C-24).

3. Unit-Level Allocations of Emissions Allowances

For states participating in the CSAPR Group 3 trading program, EPA proposes to issue CSAPR NOX Ozone Season Group 3 allowances to be used for compliance beginning with the 2021 ozone season. This section explains the process by which EPA proposes to allocate these allowances to existing units and new units in each state up to that state's budget. For existing units, EPA is proposing to apply the same allocation methodology finalized in the CSAPR Update but using updated data. This methodology considers both a unit's historical heat input and its maximum historical emissions. See 81 FR 74564-65. For new units, EPA is proposing to apply the same two-round allocation methodology finalized in the CSAPR Update for the 2021 and 2022 control periods and a similar, but less complex, one-round methodology starting with the 2023 control period. This section also describes allocation to the new unit set-asides (NUSA) and Indian Country new unit set-asides in each state; allocation to units that are not operating; and the recordation of allowance allocations in facility compliance accounts.

a. Allocations to Existing Units

EPA in this action proposes to allocate allowances to existing units in the Group 3 states following the same methodology for allowance allocation that was used in the CSAPR Update, except that the historical heat input and other data used within this methodology to establish unit-level allocations would be updated to the most recent period for which EPA has data. The portion of a state budget allocated to existing units in that state would be the state budget minus the state's new unit set-aside and minus the state's Indian country new unit set-aside. The new unit set-asides are portions of each budget reserved for new units that might locate in each state or in Indian country in the future. For the proposed existing source level allocations, see the Proposed Rule TSD “Unit Level Allocations and Underlying Data for the CSAPR for the 2008 Ozone NAAQS,” in the docket for this rulemaking. The only allowance allocations that would be updated in this final rule are allocations of CSAPR NOX Ozone Season Group 3 allowances issued under and used for compliance in the Group 3 trading program. EPA is not proposing to change allocations of allowances used in the CSAPR NOX Ozone Season Group 1 or Group 2, NOX Annual, or SO2 Group 1 or Group 2 trading programs and is not reopening the previously established allocations under these programs.

For the purpose of allocations, the CSAPR considered an “existing unit” to be a unit that commenced commercial operation prior to January 1, 2010, and the CSAPR Update considered an “existing unit” to be a unit that commenced commercial operation prior to January 1, 2015. For the 12 states subject to new or amended FIPs in this rulemaking, EPA proposes to consider an “existing unit” for purposes of the Group 3 program to be a unit that commenced commercial operation prior to January 1, 2019, and that does not cease operation before January 1, 2021. This change will allow units commencing commercial operation between 2015 and 2019 to be directly allocated allowances from each state's budget as existing units and will allow the new unit set-asides to be fully reserved for any future new units locating in covered states or Indian country. Using data available at the time of proposal development, EPA has identified which units in the proposed Group 3 states that currently submit quarterly emissions reports to EPA appear to be eligible or ineligible to receive allowance allocations as existing units; [153] for the final rule, EPA anticipates that the lists of units will be updated with the most recent data. EPA is not proposing to reconsider which units are “existing units” for purposes of any other CSAPR trading program. Start Printed Page 69013Sources in most of the proposed Group 3 states also participate in the CSAPR NOX Annual and SO2 Group 1 trading programs, for which an “existing unit” is a unit that commenced commercial operation before January 1, 2010. Thus, a unit that is located in one of these states and that commenced commercial operation between January 1, 2010, and January 1, 2019, would be considered an “existing unit” for purposes of the Group 3 trading program but would continue to be considered a “new unit” for purposes of the CSAPR NOX Annual and SO2 Group 1 trading programs.

EPA proposes to apply the methodology finalized in the CSAPR Update for allocating emission allowances to existing units, updated to the most recent years of relevant data by the respective publication dates of this proposed and final action. This methodology allocates allowances to each unit based on the unit's share of the state's heat input, limited by the unit's maximum historical emissions. As discussed in the CSAPR Update, see 81 FR 74563-65, EPA finds this allowance allocation approach to be fuel-neutral, control-neutral, transparent, based on reliable data, and similar to allocation methodologies previously used in the CSAPR, the NOX SIP Call, and the Acid Rain Program.[154] EPA is therefore proposing the continued application of this methodology for allocating allowances to existing sources in this proposed rule. Under the CSAPR Update, if, at the time the rule was finalized, a state had already submitted a SIP revision addressing the allocation of the CSAPR NOX ozone season allowances among the units in the state, and if the SIP submission's allocation provisions could be applied to an updated budget, the state's preferred allocation methodology would govern the allocation of allowances among that state's units under the final CSAPR Update. Two of the proposed Group 3 states (Indiana and New York) have such methodologies for allocating the CSAPR NOX Ozone Season Group 2 allowances among their units. EPA is proposing to carry out the intent of these SIPs by establishing initial allowance allocations to existing units under the FIPs for these two states using the allocation methodologies already adopted by the states.

This proposed rule uses the average of the three highest years of heat input data out of the most recent five-year period to establish the heat input baseline for each unit.[155] These heat input data are used to calculate each unit's proportion of state-level heat input (the average of the unit's three highest non-zero years of heat input divided by the total of such averages within the given state). In general, EPA applies this proportion to the total amount of existing unit allowances to be allocated to quantify unit-level allocations. However, EPA constrains the unit-level allocations so as not to exceed each unit's maximum historical baseline emissions, calculated as the highest year of emissions out of the most recent eight-year period.[156] This proposal evaluates 2015-2019 heat input data and 2012-2019 emissions data, which are the most recent data available as of proposal publication. EPA proposes to recalculate unit level allocations with the most recent five years of heat input and the most recent eight years of emissions data along with the most recent supporting data in the final rule.

As under both the CSAPR and the CSAPR Update, states would have several options under this proposed rulemaking to submit SIP revisions which, if approved, may result in the replacement of EPA's default allocations with state-determined allocations for the 2022 control period and beyond. The provisions described above will not preclude any state from submitting an alternative allocation methodology for later control periods through a SIP submission. See section VIII.D. for details on the development of approvable SIP submissions.

EPA requests comment on the proposed approach for allocating allowances to existing units (Comment C-25).

b. Allocations to New Units

Consistent with the updates to which units are considered to be “existing units” described above, for purposes of this proposed rule a “new unit” that is eligible to receive allocations from the new unit set-aside (NUSA) for a state includes any covered unit that commences commercial operation on or after January 1, 2019, as well as a unit that becomes covered by meeting applicability criteria subsequent to January 1, 2019; a unit that relocates to a different state covered by a FIP promulgated by this rule; and an “existing” covered unit that ceases operation for two consecutive years following the start of program implementation (thereby losing its previous allowance allocation as an “existing” unit) but that resumes operation at some point thereafter. EPA is also proposing allocations to a NUSA for each state equal to a minimum of 2 percent of the total state budget, plus the projected amount of emissions from planned units in that state. For instance, if planned units in a state are projected to emit 3 percent of the state's NOX ozone season emission budget, then the new unit set-aside for the state would be set at 5 percent, which is the sum of the minimum 2 percent set-aside plus an additional 3 percent for planned units. This is the same approach currently used to implement the NUSA for all the CSAPR trading programs. See 76 FR 48292 (August 8, 2011). Note that New York has set its NUSA percentage within its approved SIP to 5 percent without consideration of planned units; therefore, this NUSA percentage is proposed to be used for New York. Pursuant to the CSAPR regulations, new units may receive allocations starting with the first year they are subject to the allowance-holding requirements of the rule. If the allowances in the NUSA remain unallocated to new units, the allowances from the set-asides are redistributed to existing units before each compliance deadline.Start Printed Page 69014

Table VIII.C.3-1—CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for 2021

StateEmission budgets (tons)New unit set-aside amount (percent)Total new unit set-aside amount for new units (tons)New unit set-aside amount for new units not in Indian country (tons)Indian country new unit set-aside amount (tons)
Illinois9,4442181181
Indiana12,5002253253
Kentucky14,3842289289
Louisiana15,402345944415
Maryland1,52223131
Michigan12,727338437113
New Jersey1,25322727
New York3,13751571543
Ohio9,6053285285
Pennsylvania8,0764326326
Virginia4,54429191
West Virginia13,6862273273

Table VIII.C.3-2—CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for 2022

StateEmission budgets (tons)New unit set-aside amount (percent)Total new unit set-aside amount for new units (tons)New unit set-aside amount for new units not in Indian country (tons)Indian country new unit set-aside amount (tons)
Illinois9,4152181181
Indiana11,9982238238
Kentucky11,9362240240
Louisiana14,871344543015
Maryland1,49823333
Michigan11,767335234012
New Jersey1,25322727
New York3,13751571543
Ohio9,6763291291
Pennsylvania8,0764326326
Virginia3,65627676
West Virginia12,8132261261

Table VIII.C.3-3—CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for 2023

StateEmission budgets (tons)New unit set-aside amount (percent)Total new unit set-aside amount for new units (tons)New unit set-aside amount for new units not in Indian country (tons)Indian country new unit set-aside amount (tons)
Illinois8,3972173173
Indiana11,9982238238
Kentucky11,9362240240
Louisiana14,871344543015
Maryland1,49823333
Michigan9,803329628610
New Jersey1,25322727
New York3,13751571543
Ohio9,6763291291
Pennsylvania8,0764326326
Virginia3,65627676
West Virginia11,8102236236
Start Printed Page 69015

Table VIII.C.3-4—CSAPR NOX Ozone Season Group 3 New Unit Set-Aside (NUSA) Amounts for 2024 and Beyond

StateEmission budgets (tons)New unit set-aside amount (percent)Total new unit set-aside amount for new units (tons)New unit set-aside amount for new units not in Indian country (tons)Indian country new unit set-aside amount (tons)
Illinois8,3972173173
Indiana9,4472188188
Kentucky11,9362240240
Louisiana14,871344543015
Maryland1,49823333
Michigan9,614328727710
New Jersey1,25322727
New York3,11951561533
Ohio9,6763291291
Pennsylvania8,0764326326
Virginia3,39526868
West Virginia11,8102236236

For the control periods in 2021 and 2022, EPA proposes to apply the same two-round approach for allocating allowances from each state's NUSA to eligible units as EPA has historically used in all the previous CSAPR trading programs. Under this approach, in the first round, which is carried out during the control period at issue, any eligible units in the state that operated during the preceding control period are allocated allowances in proportion to their respective emissions during that preceding control period, up to the amounts of those emissions if the NUSA contains sufficient allowances. In the second round, which is carried out after the end of the control period at issue, if the first-round allocations did not exhaust the NUSA, any eligible units in the state that commenced operation in the control period or the preceding control period are allocated additional allowances in proportion to the positive differences (if any) between their emissions during the control period and their first-round allocations, up to the amounts of those differences if the NUSA contains sufficient allowances. Any allowances remaining in the NUSA after the second round are reallocated to the existing units in the state.

For control periods in 2023 and thereafter,[157] EPA proposes to replace the two-round approach described above—for purposes of both the new Group 3 trading program and the existing CSAPR trading programs—with a one-round approach that would be carried out after the end of the control period at issue. Under the proposed one-round approach, any eligible units in the state that operated during the control period will be allocated allowances in proportion to their respective emissions during the control period, up to the amounts of those emissions if the NUSA contains sufficient allowances. EPA believes this one-round approach would be both less complex than the two-round approach and more equitable, because it would avoid potential situations under the two-round approach where the newest units may not receive any NUSA allocations. In order to provide sufficient time to carry out the one-round approach after the end of the control period, several deadlines would be extended (again, for purposes of both the new Group 3 trading program and the existing trading programs) starting with the control periods in 2023. Specifically, the deadline for EPA to promulgate a notice regarding preliminary calculations of NUSA allocations would be set at March 1 after the control period; the deadline for EPA to promulgate a notice regarding the final calculations and to record the NUSA allocations would be set at May 1 after the control period; the “allowance transfer deadline” by which sources must hold sufficient allowances to cover their emissions during the control period would be set at June 1 after the control period; and the date as of which each source's “common designated representative” is determined for purposes of the assurance provisions would be set at July 1 after the control period. The proposed changes and EPA's rationale are discussed further in section VIII.C.8.

EPA requests comment on the proposed approach for reserving portions of the budgets as new unit set-asides and allocating allowances to new units (Comment C-26).

c. Allocations to New Units in Indian Country

Clean Air Act programs on Indian reservations and other areas of Indian country over which a tribe or EPA has demonstrated that a tribe has jurisdiction generally may be implemented either by a tribe through an EPA-approved tribal implementation plan (TIP) or EPA through a FIP. Tribes may, but are not required to, submit TIPs. Under EPA's Tribal Authority Rule (TAR), 40 CFR 49.1-49.11, EPA is authorized to promulgate FIPs for Indian country as necessary or appropriate to protect air quality if a tribe does not submit and receive EPA approval of a TIP. See 40 CFR 49.11(a); see also 42 U.S.C. 7601(d)(4). To date, no tribes have sought approval of a TIP implementing the good neighbor provision at CAA section 110(a)(2)(D)(i)(I) with respect to the 2008 ozone NAAQS. EPA has therefore determined that it is necessary and appropriate for EPA to implement the FIPs in any affected Indian reservations or other areas of Indian country over which a tribe has jurisdiction. However, there are no existing units that would qualify as “covered units” in Indian country located in the proposed Group 3 states under this proposal.

EPA is proposing to generally apply the CSAPR Update approach for allocating allowances to any new units located in Indian country, with parallel modifications to those described above with respect to unit-level allocations from the new unit set-asides for units not in Indian country. Under this approach, allowances to possible future new units located in Indian Country would be allocated by EPA from an Indian country new unit set-aside established for each state with Indian Start Printed Page 69016country. EPA proposes to reserve 0.1 percent of the total state budget for new units in Indian Country within that state (5 percent of the minimum 2 percent new unit set-aside,[158] without considering any increase in a state's new unit set-aside amount for planned units). Because states generally have no SIP authority in these areas, EPA would continue to handle the allocation of allowances to any sources that locate in such areas of Indian country within a state over which a tribe or EPA has demonstrated that a tribe has jurisdiction, even if the state submits a SIP to replace the applicable FIP. Unallocated allowances from a state's Indian country new unit set-aside would be returned to the state's new unit set-aside and allocated according to the methodology for that new unit set-aside.

For the control periods in 2021 and 2022, EPA proposes to apply the same two-round approach for allocating allowances from each state's Indian country NUSA to eligible units as EPA has historically used in all the previous CSAPR trading programs, and for control periods in 2023 and thereafter,[159] EPA proposes to apply a one-round approach as described above for other NUSAs. The proposed change to a one-round allocation approach for Indian country NUSAs would involve the same deadline extensions as discussed above with respect to other NUSAs and would also apply with respect to Indian country NUSAs under the existing CSAPR trading programs. Further discussion is provided in section VIII.C.8.

EPA requests comment on the proposed approach for reserving portions of the budgets as Indian country new unit set-asides and allocating allowances to new units in Indian country (Comment C-27).

d. Treatment of Allowances Allocated to Units That Cease Operations

EPA is proposing to apply the same approach followed in the CSAPR Update for reallocating allowances that were previously allocated to units that cease operations. Specifically, EPA proposes that a covered unit that does not operate for a period of two consecutive years after the start of trading program implementation will receive allowance allocations for a total of up to five years of non-operation. As in the CSAPR Update, this approach mitigates concerns that loss of allowance allocations could be an economic consideration that would cause a unit, which would otherwise retire, to continue operations in order to retain ongoing allowance allocations. Pursuant to this provision, starting in the fifth year after the first year of non-operation, EPA proposes that allowances previously allocated to such units would instead be allocated to the new unit set-aside for the state in which the non-operating unit is located. This approach allows the balance of allowance allocations to shift over time from existing units to new units, aligned with transition of the EGU fleet from older generating resources to newer ones. Allowances in the new unit set-aside that are not used by new units would be reallocated to existing units in the state. EPA proposes to retain this same CSAPR Update timeline for allowance allocation for non-operating units in this rulemaking. EPA requests comment on the proposed approach for addressing allowances allocated to units that have ceased operation (Comment C-28).

In order to accommodate a changing power sector and account for units that permanently retire and therefore no longer have emissions, EPA is taking comment on whether the NUSA should be modified such that allowances from these units that are placed in the NUSA should not be reallocated at the end of the year. Ultimately, in the absence of new units, these allowances would be redistributed to existing units. EPA seeks comment on whether allowances from retired units should remain in the NUSA rather than being redistributed to existing units, except in the event that those allowances are allocated to new units (Comment C-29).

Alternatively, in order to accommodate a changing power sector and account for the year-to-year variation in generation and potential change in usage of units over time, EPA is seeking comment on an allocation alternative (Comment C-30). Noting that budgets are based on a constant level of heat input over time and that heat input levels have generally decreased over time, EPA asks for comment on the possibility of initially distributing the average budget level of allowances per control period minus the variability limit (i.e., 79 percent of budget given a variability limit of 21 percent). Then, if the actual observed heat input for a given control period is greater than the heat input amount assumed in the original allocation, additional supplemental allowances would be provided up to the assurance level (i.e. 121 percent of the regional emission budget). In this methodology, the actual number of allowances allocated each control period would be explicitly tied to the heat input of that same control period. As an example, consider an original allowance allocation based on 79 percent of the aggregate Group 3 budget. If, after the conclusion of the ozone season, heat input is only 3 percent below the heat input level assumed in the emission budget, EPA would then allocate allowances to cover the remaining percentage of allowances withheld from the initial allocation.

4. Transitioning From Existing CSAPR NOX Ozone Season Group 2 Trading Program

This section discusses three sets of provisions that EPA proposes to implement in order to address the transition of sources from the Group 2 trading program to the Group 3 trading program. First, to address the possibility that final action on this proposal may not become effective until after May 1, 2021, and to ensure that under those circumstances the Group 3 trading program could be implemented for the full May-September ozone season in 2021 without imposing retroactive emission reduction requirements, EPA is proposing to allocate additional allowances, and to make corresponding adjustments to states' 2021 assurance levels, so as to offset the otherwise applicable emission reduction requirements under this rulemaking for any portion of the 2021 ozone season that may occur before the final rule's effective date. Second, in order to facilitate the continued use of market-based trading programs as the compliance mechanism for sources covered by this action while ensuring an appropriate level of stringency in the Group 3 trading program, EPA is proposing a process by which certain banked CSAPR NOX Ozone Season Group 2 allowances will be converted to CSAPR NOX Ozone Season Group 3 allowances. Finally, 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 action, EPA is also proposing that the CSAPR NOX Ozone Season Group 2 allowances equivalent in amount and vintage to the previously allocated vintage year 2021-2024 CSAPR NOX Ozone Season Group 2 allowances in the new Group 3 region will be recalled.Start Printed Page 69017

a. Supplemental Allowance Allocations To Avoid Retroactive Emission Reduction Requirements

EPA expects to take a final action in this rulemaking by March 15, 2021 and anticipates that the final rule will be published in the Federal Register by early April, before the start of the 2021 ozone season on May 1, 2021. However, because of the requirements of the Congressional Review Act (CRA), 5. U.S.C. 801-808, EPA is unable at this time to predict whether the increased trading program stringency established in the final rule will take effect as of May 1, 2021. Under CRA section 801(a)(3), a “major rule,” as defined under the CRA, generally may not take effect sooner than 60 days after the date of publication in the Federal Register (or, if later, 60 days after the date on which Congress receives a report on the final rule from EPA). Under CRA section 804(2), a “major rule” includes any rule that the Office of Management and Budget (OMB) finds is likely to result in an annual effect on the economy of $100 million or more. Because the final action in this rulemaking is projected to result in annualized benefits greater than $100 million per year, as discussed in section IX of the preamble, it is possible that OMB could find that the final action on this proposal would be a “major rule” for CRA purposes, in which case the rule's effective date could occur after the start of the 2021 ozone season.

EPA proposes to find that, notwithstanding that the final rule's requirements may not be able to take effect until after May 1, 2021, it would nevertheless 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 in Group 3 states—to start on May 1, 2021. This will facilitate implementation of the Group 3 trading program in an orderly manner for the entire 2021 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 2021 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 into separate years is not a viable approach, because EPA would have no legal basis for releasing the Group 3 sources from the emission reduction requirements found to be necessary in the CSAPR Update for a portion of the 2021 ozone season, and EPA similarly would have no legal basis for deferring implementation of the 2021 emissions reduction requirements found to be necessary under this rule until 2022. Moreover, the requirements of the Group 2 trading program and the Group 3 trading program are substantively identical as to almost all provisions, such that with respect to those provisions, a source would 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, EPA believes that no substantive concerns regarding retroactivity would arise from implementing the Group 3 trading program starting on May 1, 2021, so long as those aspects of the Group 3 trading program 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.

Thus, with respect to two aspects of the proposed rule, EPA proposes the following adjustments in 2021 ozone season obligations in order to ensure no new requirements are imposed on any regulated parties prior to the effective date of the final rule.

To cause the more stringent budgets of the Group 3 trading program to apply only after the effective date of the final rule, EPA proposes to make supplemental allocations of Group 3 allowances to Group 3 sources for the portion of the 2021 ozone season occurring before the effective date of the final rule. The total amount of the supplemental allowances available for allocation to the sources in each state would be calculated by multiplying the difference between the state's Group 2 and Group 3 budgets by the fraction of the 2021 ozone season, measured in days, occurring before the final rule's effective date. The state's total amount of supplemental allowances would then be allocated among the state's existing units as if the supplemental allowances had been included in the state's 2021 emissions budget for the Group 3 trading program. The allocations of supplemental allowances would be recorded at the same time as the allocations from the budget.

To cause the more stringent assurance levels of the Group 3 trading program to apply only after the effective date of the final rule, EPA proposes to include an increment in each state's assurance level for 2021 in addition to the state's emissions budget and variability limit for 2021. The amount of the increment would be computed as 1.21 times the total amount of supplemental allowances determined for the state as described above, where 1.21 is the ratio of the Group 2 state assurance levels to the Group 2 state budgets and is also the ratio of the proposed Group 3 state assurance levels to the proposed Group 3 state budgets. In the event of an exceedance of a state's assurance level, the allocations of supplemental allowances and the increment to the state's variability limit would also be taken into account for purposes of the calculations used to apportion responsibility for any exceedance of a state's assurance level among the owners and operators of the state's sources.

In all respects other than the allocation of supplemental Group 3 allowances and the addition of an increment to the states' assurance levels, EPA proposes to implement the Group 3 trading program for the 2021 control period exactly as the program would be implemented for any other control period. Thus, allocations of Group 3 allowances from each state's emissions budget to existing and new units would be made for the entire 2021 ozone season (i.e., May 1, 2021 through September 30, 2021), emissions would be monitored and reported for the entire 2021 ozone season, and as of the allowance transfer deadline for the 2021 control period (i.e., March 1, 2022) each source would be required to hold in its compliance account vintage-year 2021 Group 3 allowances not less than the source's emissions of NOX during the entire 2021 ozone season. Because of the supplemental allowances allocated for the portion of the 2021 ozone season before the rule's effective date, EPA proposes to find that implementing the program in this manner would substantively apply the final rule's emissions reduction requirements only from the rule's effective date. Similarly, because of the increment to the states' assurance levels for 2021, EPA proposes to find that implementing the trading program in this manner would substantively apply the final rule's more stringent assurance levels only from the rule's effective date. Moreover, any efforts undertaken by a source to reduce its emissions during the portion of the Start Printed Page 690182021 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 Group 3 trading program.

EPA requests comment on the proposed approach for implementing the Group 3 trading program in a manner that would apply the substantive increases in stringency established under the final rule on and after, but not before, the final rule's effective date (Comment C-31).

b. Creation of Initial Group 3 Allowance Bank

For this rulemaking, EPA is proposing to convert allowances banked in 2017-2020 under the CSAPR NOx Ozone Season Group 2 Trading Program into a limited number of allowances that can be used for compliance in the CSAPR NOx Ozone Season Group 3 Trading Program. Any treatment of banked allowances must ensure that implementation of the Group 3 trading program will result in NOX emission reductions sufficient to address significant contribution in the 12 linked Group 3 states, 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 use of a conversion ratio for banked allowances from the CSAPR ozone season trading program was upheld in Wisconsin v. EPA, see 938 F.3d at 321.

Similar to the approach taken in the CSAPR update, EPA is proposing a one-time conversion of banked Group 2 allowances according to a formula which ensures that emissions in the Group 3 trading program region in the first year of the program do not exceed a specified level (defined as emissions up to the sum of the states' seasonal emissions budgets and variability limits) as a result of the use of banked allowances from the Group 2 trading program. EPA proposes to carry out the conversion no later than 180 days after the date of publication of the final action in this rulemaking in the Federal Register. The conversion would occur after the surrenders of allowances for compliance for the 2020 control period are completed by March 1, 2021, which is the allowance transfer deadline. The proposed conversion ratio would be calculated by a formula, the numerator of which would be the total number of banked Group 2 allowances held as of the deadline by owners or operators of facilities in Group 3 states plus banked allowances held in “general” accounts (i.e., accounts not associated with a source), and the denominator of which would be the sum of the Group 3 states' 2022 control period variability limits proposed in this rule multiplied by the fraction of the 2021 ozone season, measured in days, occurring after the final rule's effective date. The quotient, or ratio (or a factor of 1.0000, if the quotient is less than 1.0000), would then be applied to the banked vintage year 2017-2020 Group 2 allowances in each such account to yield the number of banked allowances that would be made available to the holder of each such account for compliance under the Group 3 trading program for the 2021 control period. As discussed in section VIII.C.2, the proposed variability limits differ by year. EPA proposes to use the variability limits for the 2022 control period in the formula because 2022 is the first year in which the proposed budgets, and therefore the proposed variability limits, would reflect the full set of control technologies represented by the $1600 per ton cost level proposed to be consistent with addressing the Group 3 states' obligations under CAA section 110(a)(2)(D)(i)(I). Thus, the proposed conversion ratio formula would yield an effective starting bank of 21 percent of the aggregated 2022 Group 3 ozone season budgets for all covered states, or 21,022 allowances, adjusted to reflect any delay in implementation of the substantive increases in stringency established under the final rule beyond May 1, 2021.

EPA proposes that before carrying out the conversion of the bank of Group 2 allowances to Group 3 allowances, all general accountholders would be given an opportunity to temporarily transfer out of their general accounts any Group 2 allowances that they would prefer to retain for potential subsequent use in the Group 2 trading program. By 150 days after publication of a final rule in this rulemaking, EPA would create a common holding account for Group 2 allowances. General accountholders who hold Group 2 allowances could elect to transfer any number of their Group 2 allowances to this holding account by a deadline of 30 days after the creation of the Group 2 holding account. Group 2 allowances held in a facility compliance account could not be transferred directly to the holding account but could be transferred to a general account and then to the holding account. After the 30-day transfer window, EPA would implement a seven-day account freeze to execute the conversion. For the duration of the freeze, accountholders could not execute any transfers into or out of any general or facility compliance account that held Group 2 allowances at the beginning of the freeze. During this seven-day freeze, all Group 2 allowances held in any general or facility compliance account—but not the Group 2 allowances held in the common Group 2 holding account—would be converted to vintage year 2021 Group 3 allowances, per the conversion methodology described above. After the conversion is carried out, EPA would transfer all Group 2 allowances held in the common Group 2 holding account back to the general accounts from which they were transferred into the common Group 2 holding account.

EPA requests comment on the proposed conversion of banked 2017-2020 Group 2 allowances into a limited initial bank of Group 3 allowances. EPA also requests comment on whether the minimum conversion ratio should be a number greater than 1.0000, based on a formula that would provide an incentive to convert a minimum number of banked Group 2 allowances to Group 3 allowances, thereby preserving the stringency of the Group 2 trading program established in the CSAPR Update. Specifically, while the denominator of such a minimum ratio formula would be the same sum of the Group 3 states' variability limits under the Group 3 trading program that would be used in the primary conversion ratio formula, the numerator of the minimum ratio formula would be the total quantity of banked 2017-2020 Group 2 allowances attributable to sources in the states moving to the new Group 3 trading program (i.e., the sum of the differences between the Group 3 states' budgets under the Group 2 trading program for the 2017-2020 ozone seasons and the total NOX emissions from sources in those states in the 2017-2020 ozone seasons, plus the portion of the initial bank of allowances created for the Group 2 trading program that was attributable to the variability limits of those same states under the Group 2 trading program) (Comment C-32).

c. Recall of Group 2 Allowances Allocated for Control Periods After 2020

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 action, EPA is also proposing to recall CSAPR NOX Ozone Season Group 2 allowances equivalent in amount and vintage to all vintage Start Printed Page 69019year 2021-2024 CSAPR NOX Ozone Season Group 2 allowances previously allocated to sources or non-source entities in Group 3 states. Specifically, 60 days after the date of Federal Register publication of the final action in this rulemaking, EPA would establish a 30-day window for the owners or operators of sources (or the representatives of non-source entities) in Group 3 states to transfer into their relevant compliance or general accounts the number of vintage year 2021-2024 CSAPR NOX Ozone Season Group 2 allowances equal to the number that were allocated for each of these control periods (i.e., 2021, 2022, 2023, and 2024) to all units at the source or to the non-unit entity. EPA intends to issue notifications and instructions to each accountholder to ensure the correct numbers of allowances of each vintage are returned. As noted in section VIII.C.7., EPA proposes not to record any allocations of Group 3 allowances to a source or other entity unless that source or entity has complied with the requirements to surrender previously allocated 2021-2024 Group 2 allowances. In addition, failure to comply with the recall provisions is proposed to be subject to potential enforcement as a violation of the Clean Air Act, in the same way that failure to hold sufficient allowances to cover emissions and failure to comply with the allowance surrender requirements of the assurance provisions in the regulations for all of the existing CSAPR trading programs is subject to such potential enforcement, with each allowance and each day of the control period constituting a separate violation.

EPA requests comment on the proposed approach for recalling 2021-2024 Group 2 allowances previously allocated to sources and other entities in Group 3 states (Comment C-33).

5. Compliance Deadlines

As discussed in section V.C. of this preamble, the proposed rule requires sources to comply with the revised respective NOX emission budgets for the 2021-2024 ozone seasons (May 1 through September 30 of each year) in order to ensure that these necessary NOX emission reductions are implemented to assist in downwind states' attainment and maintenance of the 2008 ozone NAAQS by the 2021 Serious area attainment date. Thus, under the new CSAPR NOx Ozone Season Group 3 Trading Program proposed by EPA in this rulemaking, the first control period is the 2021 ozone season (i.e. May 1, 2021, through September 30, 2021). This initial control period is coordinated with the attainment deadline for the 2008 standard, and the proposed rule includes provisions to ensure that all necessary reductions occur at sources within each individual state.

Under all CSAPR trading programs, compliance at the source level is achieved by each source surrendering by a compliance deadline—defined in the regulations at 40 CFR 97.802 as the “allowance transfer deadline”—a number of allowances equal to the source's total emissions for the preceding ozone-season control period. For the control periods in 2021 and 2022, EPA proposes that the deadline by which sources must hold Group 3 allowances in their facility compliance accounts at least equal to their emissions is March 1 of the year following the control period. This deadline is the same as the current deadline for holding allowances under all the existing CSAPR trading programs. Under this coordinated deadline, March 1, 2022 is the proposed date by which Group 3 sources will be required to hold Group 3 allowances for compliance purposes of the 2021 ozone season control period. Likewise, the proposed date for purposes of the 2022 ozone season is March 1, 2023.

For control periods in 2023 and thereafter,[160] EPA proposes that the allowance transfer deadline for the Group 3 trading program—and for all the other CSAPR trading programs [161] —be moved from March 1 to June 1 of the year after the control period. The reason for the proposed change is to accommodate a proposed change in the methodology and schedule for allocating allowances to units from the new unit set-asides that would start with the 2023 control periods. Under that revised methodology, allowances from the new unit set-asides would be recorded in units' compliance accounts by May 1 of the year following the control period, and some additional period after that date is needed to allow for allowance purchases in case a source receives fewer allowances from the new unit set-aside than anticipated. Under the current regulations at 40 CFR 97.812, the deadline for recording second-round allocations from the new unit set-asides is February 15, two weeks before the March 1 allowance transfer deadline. EPA believes sources would have greater trading flexibility if this interval were extended to a full month, resulting in the proposed allowance transfer deadline of June 1. Extension of the allowance transfer deadline is not expected to have any impact on the achievement of the CSAPR trading programs' environmental objectives because it would not affect the quantities of allowances that sources will be required to hold as of the deadline or the total quantities of allowances that will be made available for compliance in advance of the deadline. Further discussion is provided in sections VIII.C.3.b. and VIII.C.8.

EPA requests comment on the proposed compliance deadlines (Comment C-34).

6. Monitoring and Reporting

Monitoring and reporting in accordance with the provisions of 40 CFR part 75 are required for all units subject to all the CSAPR trading programs, which includes all units covered under this proposed rule. Consistent with these existing requirements, EPA proposes that the monitoring system certification deadline by which monitors are installed and certified for compliance use under the CSAPR NOx Ozone Season Group 3 Trading Program generally will be May 1, 2021, the beginning of the first control period in this proposed rule, with potentially later deadlines for units that commence commercial operation less than 180 days before that date. Units already in compliance with monitoring system certification requirements for the Group 2 trading program would not have to undertake any additional activities to certify their monitoring systems for the Group 3 trading program. Similarly, EPA proposes that the first period in which emission reporting is required would be the quarter that includes May 1, 2021, (i.e., the second quarter of the year that covers April, May, and June). These monitoring and reporting requirements and deadlines are analogous to the current deadlines under the CSAPR NOx Ozone Season Group 2 Trading Program.

Under 40 CFR part 75, a unit has several options for monitoring and reporting, including the use of a CEMS; an excepted monitoring methodology based in part on fuel-flow metering for certain gas- or oil-fired peaking units; low-mass emissions monitoring for certain non-coal-fired, low emitting Start Printed Page 69020units; or an alternative monitoring system 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 and result in 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 will contain all of the data required concerning ozone season NOX emissions.

Units currently subject to the CSAPR NOx Ozone Season Group 2 Trading Program are required to monitor and report NOX emissions in accordance with 40 CFR part 75, so covered sources in the Group 3 trading program will simply continue the same monitoring and reporting practices as required by 40 CFR part 75 under the Group 2 trading program.

7. Recordation of Allowances

EPA is proposing to establish a schedule for recording allocations of vintage-year 2021 CSAPR NOX Ozone Season Group 3 allowances to ensure that affected sources are allocated vintage year 2021 allowances as soon as practicable and well before the 2021 ozone season compliance deadline (March 1, 2022). EPA is also proposing a schedule for recording allocations of vintage-year 2022 CSAPR NOX Ozone Season Group 3 allowances that accommodates sources' expectation to receive these allowance allocations soon after the publication of this final rule while also ensuring that states have the opportunity to develop and submit to EPA SIP revisions concerning allocations of allowances for vintage year 2022 and later.

Specifically, allocations to existing units for the first control period outlined in this proposal (i.e. the 2021 ozone season) will be recorded no later than 120 days after the publication of the final rule in the Federal Register. EPA will also record allocation of vintage year 2022 allowances by this deadline for all units except those in states that provided to EPA, by 90 days after the publication of the final rule, a letter indicating an intent to submit a SIP revision that, if approved, would substitute state-determined allocations for the default allocations determined by EPA for the 2022 control period. EPA proposes that the deadline for states to submit to EPA such SIP revisions will be 180 days after publication of the final rule. If states that notified EPA of their intent to submit a SIP revision fail to submit such a SIP by the SIP submission deadline, EPA will record vintage year 2022 FIP allocations to those states no later than 210 days after the publication of the final rule. No later than one year after the publication of the final rule, EPA will record the SIP allocations of vintage year 2022 Group 3 allowances for states with approved SIP revisions. By this same one-year deadline, EPA will record the FIP allocations of vintage year 2022 Group 3 allowances for states whose SIP revisions are not approved by EPA.

The recordation deadline for vintage year 2021 allowances to existing units is anticipated to be approximately 7 months before the date by which sources are required to hold allowances sufficient to cover their emissions for that first control period (March 1, 2022, as discussed above). This schedule allows sources ample time to engage in allowance trading activities consistent with their preferred compliance strategies. EPA proposes to record vintage year 2023 and 2024 Group 3 allowance allocations to existing units by July 1, 2022, and vintage year 2025 and 2026 Group 3 allowance allocations by July 1, 2023. By July 1 of each year after 2023, EPA proposes to record Group 3 allowance allocations to existing units for the control period in the third year after the year of recordation. The proposed recordation deadlines would apply to recordation of both allocations based on the default proposed allocation provisions and allocations provided by states pursuant to approved SIP revisions.

As an exception to all of the recordation deadlines that would otherwise apply, EPA proposes not to record any allocations of Group 3 allowances to a source or other entity unless that source or entity has complied with the requirements to surrender previously allocated 2021-2024 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 proposal. EPA believes that conditioning the recordation of Group 3 allowances on compliance with the surrender requirements would spur compliance and would not impose an inappropriate burden on sources.

EPA notes that the proposal to generally record allocations to existing units three years in advance under the new Group 3 trading program represents a change from the historical recordation schedules for allocations to existing units under the other CSAPR trading programs, which have generally provided for such allocations to be recorded four years in advance. In this action, EPA is proposing to revise the recordation schedules under the other CSAPR trading programs, as well as the similarly structured Texas SO2 Trading Program, so as to generally record allocations to existing units three years in advance. The proposed change would take effect with allocations for the 2025 control periods, which would be recorded by July 1, 2022, instead of by July 1, 2021. The reason for the proposed change is the discovery of a timing conflict in all the CSAPR trading programs between the requirement to record four years in advance and the separate provisions governing allocations to existing units that have ceased operations. Under those separate provisions, EPA is unable to determine whether some existing units are entitled to continue to receive their allowance allocations more than three years in advance, and thus EPA does not have the information necessary to record all the allocations four years in advance. Further discussion of this proposed revision to the schedule for recording allocations to existing units is provided in section VIII.C.8.a.

With respect to allocations of allowances from the new unit set-asides and Indian country new unit set-asides, for the 2021 and 2022 control periods, EPA proposes to record these allocations under the Group 3 trading program in two rounds, by August 1 of the control period (or 120 days after publication of the final rule in this action, if later) and by February 15 of the year following the control period. This schedule generally matches the recordation schedule for allocations of allowances from the analogous set-asides under the Group 2 trading program and the other CSAPR trading programs. Starting with the 2023 control period,[162] EPA proposes to adopt a new one-round process for determining allocations from the new unit set-asides and Indian country new unit set-asides, and consistent with that revised allocation process EPA proposes to Start Printed Page 69021record all allocations from these set-asides as of May 1 in the year following the control period, in both the Group 3 trading program and the existing CSAPR trading programs, and both where the allocations are determined by EPA and where the allocations are provided by states pursuant to approved SIP revisions. Further discussion is provided in sections VIII.C.3.b. and VIII.C.8.b.

EPA requests comment on the proposed recordation deadlines (Comment C-35).

8. Proposed Conforming Revisions to Regulations for Existing Trading Programs

As discussed elsewhere in this preamble, in most respects, but not in every respect, the provisions of the proposed the CSAPR NOX Ozone Season Group 3 Trading Program at 40 CFR part 97, subpart GGGGG, parallel the current provisions of the other CSAPR trading programs [163] at subparts AAAAA through EEEEE established in the CSAPR rulemaking and the CSAPR Update and, to a somewhat lesser extent, the provisions of the similarly structured Texas SO2 Trading Program established at subpart FFFFF. This section discusses the proposed provisions of the new trading program that differ from the current provisions of the existing trading programs, beyond the provisions discussed in section VIII.C.4. addressing the transition to the new trading program. This section also discusses various minor proposed corrections and clarifications to the existing regulations.

To clarify and facilitate administration of the regulations for all of EPA's trading programs in 40 CFR part 97, and to maintain their parallel nature to the extent possible, EPA is proposing in this action to amend the regulations for the existing trading programs to reflect certain revisions as noted in the sections of this preamble describing the proposed new Group 3 trading program. Section VIII.C.8.a. addresses the proposed revisions discussed in section VIII.C.7. to address a timing conflict in the current regulations for all of the existing programs. Section VIII.C.8.b. addresses the proposed revisions discussed in sections VIII.C.3.b. and VIII.C.3.c. to simplify and improve the process for allocating allowances from the new unit set-asides under the existing CSAPR programs. Section VIII.C.8.c. addresses an additional minor revision to facilitate the reallocation of any incorrectly allocated allowances and also discusses proposed small corrections to the previously published amounts of certain new unit set-asides. It is EPA's intent for the regulations for all the trading programs in 40 CFR part 97 to continue to be as consistent in design as possible. For this reason, if the existing trading programs are not amended to include the revised provisions discussed in this section, EPA requests comment on instead maintaining the parallel nature of the various trading programs by finalizing the new trading program in subpart GGGGG not as proposed, but as modified to reflect the comparable current provisions of the existing CSAPR trading programs in subparts AAAAA through EEEEE without the revised provisions that are discussed in this section and reflected in the currently proposed regulatory text for new subpart GGGGG and discussed in this section (Comment C-36).

In this action, EPA is not reopening or requesting comment on the regulations for any of the existing trading programs in 40 CFR part 97, subparts AAAAA through FFFFF, except with respect to specific revisions to these subparts proposed in this section, as well as the revisions to the regulations for the Group 2 trading program discussed in section VIII.C.4. that address the transition from the Group 2 trading program to the Group 3 trading program.

a. Resolution of Timing Conflict Between Certain Existing Provisions

Consistent with the provisions of the new CSAPR trading program proposed in this action, EPA proposes to amend the regulations for the existing CSAPR trading programs and the Texas SO2 Trading Program to resolve a timing conflict between the provisions that set deadlines for recordation of allowances allocated to existing units and the provisions that govern allocations of allowances to units that have ceased operation for the control periods in at least two consecutive years. The current recordation provisions in all of the trading programs generally require EPA to record allocations of allowances to existing units four years in advance of the control periods for which the allowances are being allocated. For example, on July 1, 2020, EPA recorded allocations to most existing units of allowances for use in the 2024 control periods for all the existing trading programs. However, other provisions of all the trading programs require EPA not to record allocations to existing units that do not operate for two consecutive control periods, starting with the fifth control period after the first control period in which the unit did not operate. For example, if a unit that would otherwise receive allocations as an existing unit does not operate in the 2019 and 2020 control periods, the unit will continue to receive allocations for the control periods in 2019 through 2023 but will no longer be entitled to receive allocations for control periods in 2024 and thereafter. These two sets of timing requirements are in conflict, as demonstrated by the examples just presented: as of the July 1, 2020 deadline to record allocations for the 2024 control periods, EPA could not yet know whether all units that did not operate in 2019 would resume operation later in 2020, and EPA therefore could not yet know whether all such units would be entitled to receive allocations for the 2024 control periods or not.[164]

To address the timing conflict described above, EPA is proposing to amend the regulations for each of the CSAPR trading programs and the Texas SO2 Trading Program to generally require recordation of allowances allocated to existing units to take place three years rather than four years in advance of the control period for which allowances are being allocated. Returning to the examples above, if these proposed amendments had been in effect with respect to allocations for the control periods in 2024, EPA would not have been required to record allocations for the 2024 control period until July 1, 2021, by which time complete information on all units' operations in 2019 and 2020 will be available. Relatedly, for states that determine allocations of allowances to their sources under approved SIP revisions, EPA is proposing to amend the deadlines by which the states must submit the allocations to EPA for recordation to make the submissions due three years instead of four years before the applicable control period.[165]

Start Printed Page 69022

The amended recordation and submission schedules are proposed to be effective beginning with recordation of allocations for control periods in 2025 and would apply to EPA's schedule for recording not only the allocations determined by EPA under the federal CSAPR trading programs but also the allocations determined by states or EPA under state CSAPR trading programs that are similarly recorded by EPA. EPA believes these proposed amendments address the timing conflict in the existing trading program regulations in a manner that is as consistent as possible with the other provisions of the regulations, because while the amendments would alter the point in time at which trading program participants receive allowances, the amendments would not alter the quantities of allowances received by any participant in any of the existing trading programs. In contrast, the only simple alternatives for resolving the timing conflict—either shortening the period of non-operation that would cause a unit to lose its allocation from two years to one year or lengthening the period for which non-operating units would retain their allowance allocations from five years to six years—would cause changes in the amounts of allowances received by some trading program participants, and some stakeholders might view those changes as inequitable or undesirable for other policy reasons.

EPA requests comment on the proposed amendments to the deadlines for EPA to record allowance allocations and for states with approved CSAPR SIP revisions to submit their state-determined allowance allocations to EPA (Comment C-37). Further details on the specific regulatory provisions that would be affected by the proposed revisions are provided in section X.D. of the preamble.

b. Modifications to NUSA Provisions

Consistent with the provisions of the new CSAPR trading program proposed in this action for ozone season emissions of NOX from sources in Group 3 states, EPA proposes to amend the regulations for the existing CSAPR trading programs governing allocations of allowances to units from NUSAs and Indian country NUSAs to reduce the potential for inequitable outcomes and to clarify and simplify the regulations.

The current regulations provide for a two-round allocation process. For purposes of the first round, a unit is generally eligible to receive allocations from the NUSA for its state regardless of when it commenced commercial operation, as long as either no allocation of allowances to the unit as an existing unit was previously determined [166] or the unit is no longer entitled to receive its previously determined allocation as an existing unit. The first-round allocations are calculated during the control period at issue and are proportional to the eligible units' emissions during the preceding control period, up to the amount of allowances available in the NUSA. EPA performs preliminary calculations and publishes a notice by June 1, provides an opportunity for objections, and then adjusts the calculations as necessary, issues a final notice, and records the allocations by August 1 of the control period.

If any allowances remain in the NUSA after the first round, EPA carries out a second round, for which eligibility is limited to units that commenced commercial operation in the year of the control period at issue or the preceding year. The second-round allocations are calculated early in the year after the year of the control period at issue (very shortly after the January 30 deadline for submission of emissions data for October through December) and are proportional to the positive differences, if any, between the eligible units' emissions during the control period at issue and the amounts of any allocations the units received in the first round, up to the remaining amount of allowances available in the NUSA. Any allowances remaining after the second round are allocated to existing units in the state in proportion to their previous allocations. EPA makes a preliminary identification of eligible units and publishes a notice by December 15, provides an opportunity for objections, and then performs the calculations, issues a final notice, and records the allocations by February 15 following the year of the control period, two weeks before the current March 1 allowance transfer deadline.

As indicated in the description above, the current procedures have the potential to produce inequitable results, where some units may receive allowances in the first round (based on their emissions in the preceding control period) that exceed the amounts needed to cover their emissions during the control period at issue, while other units that commenced operation more recently may not receive any allowances in either the first round (because the units had no covered emissions in the preceding control period) or the second round (because the NUSA may have been exhausted in the first round). Further, based on the experience of administering the two-round NUSA allocation process since 2015, EPA believes the current procedures are unnecessarily complex and cause confusion for some market participants.

To simplify the NUSA allocation process and eliminate the potential inequities noted, EPA proposes to amend the regulations for the existing CSAPR programs to replace the current two-round NUSA allocation process with a one-round process that would allocate allowances to all eligible units in proportion to their emissions in the control period at issue. The amended provisions are proposed to be effective beginning with NUSA allocations for the control periods in 2023. Under the proposed procedures, which would apply to both NUSAs and Indian country NUSAs, EPA would perform preliminary calculations and issue a notice by March 1 of the year after the control period at issue, one month after the January 30 deadline for submission of the required emission data. After providing an opportunity for objections, EPA would make any necessary adjustments, issue a final notice, and record the allowances by May 1. To accommodate this process, the proposed amendments would also revise the allowance transfer deadline (i.e., the date by which all covered sources must hold allowances in their compliance accounts sufficient to cover their emissions during the preceding control period) from March 1 of the year following the control period to June 1. In coordination with the revised recordation deadlines, EPA also proposes to extend the deadline for states to submit to EPA their state-determined allocations for new units from July 1 in the year of the control period to April 1 in the year following the control period. Finally, although the Texas SO2 Trading Program does not have NUSA provisions, in order to minimize unnecessary differences between the deadlines for analogous provisions in that program and the CSAPR programs, EPA also proposes to revise the Supplemental Allowance Pool recordation deadline and the allowance transfer deadline under the Texas SO2 Trading Program to May 1 and June 1, respectively, of the year after the control period.

The proposed revisions to the NUSA allocation procedures would also allow for related simplification of the CSAPR trading programs' assurance provisions. Start Printed Page 69023Under the current assurance provisions, when emissions in a state for a given control period exceed the state's assurance level, if there are any units in the state that operated during the control period but that did not receive an actual allowance allocation either as an existing unit or from the NUSA, the regulations require EPA to publish a notice calling for the owners and operators of such units to submit certain information which EPA uses to determine imputed allowance allocations for the units. EPA then uses the imputed allowance allocations for these units, together with the actual allowance allocations for other units, to apportion responsibility for the assurance level exceedance among the owners and operators of all the state's units. If the proposed amendments to the NUSA allocation process are adopted, all units that have covered emissions during any control period would receive allocations either as an existing unit or from the NUSA, making the procedures for determining imputed allocations unnecessary. Accordingly, EPA proposes to simplify the assurance provisions for all of the existing CSAPR trading programs by removing the requirement for EPA to issue the additional notice just discussed, starting with the 2023 control periods.[167] EPA also proposes to revise the date as of which the “common designated representative” for a group of sources is determined for purposes of the assurance provisions from April 1 to July 1 of the year following the control period, preserving that date's current position of being one month after the allowance transfer deadline. This revision would maintain the existing coordination between these two regulatory deadlines and would apply to all the existing CSAPR trading programs as well as the Texas SO2 Trading Program.

EPA is proposing to make the changes to the NUSA allocation provisions, assurance provisions, and related deadlines effective as of the 2023 control period. The 2023 control period is the first control period by which it will be possible for states to fully replace the FIP requirements that are proposed in this action with a SIP revision. In the event that any states prefer the existing two-round NUSA allocation process, they would be able to include such a process in their state rules for determining allowance allocations and submit those state rules to EPA for approval in a SIP revision. However, EPA believes it is essential that the same deadlines apply to all participants in a given CSAPR trading program, and that it is very desirable for the deadlines to be the same across all the CSAPR trading programs. EPA therefore proposes to apply all of the amended deadlines described above to all states and all sources participating in all of the CSAPR trading programs under both FIPs and SIPs as of the 2023 control periods.

EPA requests comment on the proposed revisions discussed above regarding the NUSA provisions and the associated revisions to the assurance provisions, the allowance transfer deadline, the deadline for EPA to record NUSA allocations and/or Supplemental Allowance Pool allocations, the deadline for states to submit state-determined allocations of allowances to new units, and the date for determination of a common designated representative for purposes of the assurance provisions. In addition to requesting comment on applying these revisions as of the 2023 control periods as proposed, EPA also specifically requests comment on whether it would be preferable to apply the revisions as of the 2021 control periods, in the new Group 3 trading program as well as the existing CSAPR trading programs and, to the extent applicable, the Texas SO2 Trading Program (Comment C-38). Further details on the specific regulatory provisions that would be affected by the proposed revisions are provided in section X.D. of the preamble.

c. Minor Corrections and Clarifications to Existing Regulations

EPA is proposing two additional minor corrections and clarifications to the NUSA provisions in the existing CSAPR trading programs. The first minor revision addresses circumstances where allowances that are determined to have been allocated incorrectly are recalled and added to the NUSA for reallocation. The current regulations provide for the recalled allowances to be reallocated through the NUSA allocation process for the same control period for which the allowances were originally allocated incorrectly. Because some corrections may occur after the NUSA allocation process for a control period has already have been completed, EPA proposes to revise these provisions to also allow the recalled allowances to be reallocated as part of the NUSA allocation process for a subsequent control period.

The second minor proposed revision to the NUSA provisions concerns the specific numbers of allowances identified as the NUSA amounts for several states under the existing CSAPR programs established in the CSAPR rulemaking.[168] Following the promulgation of the CSAPR regulations in August 2011, EPA issued two rules revising the amounts of the emissions budgets, NUSAs, and Indian country NUSAs for several states.[169] Subsequent to these rule revisions, EPA recalculated the allocations to individual existing units and published a notice of data availability establishing the new allocations.[170] However, because of rounding differences, in certain instances the sum of the recalculated allocations to the individual units in a state plus the amounts identified in the regulations for the NUSA and Indian country NUSA for the state does not exactly equal the state budget.[171] In this action, EPA is proposing to adjust the amounts of the NUSAs identified in the regulations for control periods in future years up or down by the amount needed to eliminate the rounding differences. The sizes of the proposed NUSA adjustments range from 1 to 17 allowances. These revisions would not affect the amounts of any state emissions budgets.

EPA requests comment on the proposed corrections and clarifications described above. Further details on the specific regulatory provisions that would be affected by the proposed revisions are provided in section X.D. of the preamble (Comment C-39).

D. Submitting a SIP

States may replace a FIP with a SIP under the Clean Air Act at any time if the SIP is approved by EPA, see CAA section 110(c)(1)(B). EPA has established certain specialized provisions for replacing FIPs with SIPs within all of the CSAPR trading programs, including the use of so-called “abbreviated SIPs” and “full SIPs,” see 40 CFR 52.38(a)(4)-(5) and (b)(4), (5), (8), and (9); 40 CFR 52.39(e), (f), (h), and (i). Under the proposed new or amended FIPs for the 12 states whose sources Start Printed Page 69024would participate in the new CSAPR NOx Ozone Season Group 3 Trading Program, “abbreviated” and “full” SIP options continue to be available. An “abbreviated SIP” allows a state to submit a SIP revision that would modify allocation provisions in the ozone season NOX trading program that is then incorporated into the FIP to allow the state to substitute its own allocation provisions. A “full SIP” allows a state to adopt a trading program meeting certain requirements that would allow sources in the state to continue to use the EPA-administered trading program through an approved SIP revision, rather than a FIP. In addition, as under the CSAPR and the CSAPR Update, 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 2022 control period—through streamlined SIP revisions. See 76 FR 48326-48332 for additional discussion on full and abbreviated SIP options and 40 CFR 52.38(b).

1. SIP Option To Modify 2022 Allocations

As under the CSAPR and the CSAPR Update, EPA proposes to allow a state to submit a SIP revision establishing allowance allocations for existing units in the state for the second control period of the new requirements, 2022, to replace the EPA-determined default allocations. The process would be the same process used at the start of other CSAPR trading programs but with slightly longer deadlines, i.e., a state would submit a letter to EPA within 90 days after publication of the final rule indicating its intent to submit a complete SIP revision within 180 days after publication of the final rule. The SIP would provide in an EPA-prescribed format a list of existing units and their allocations for the 2022 control period. If a state does not submit a letter of intent to submit a SIP revision, the EPA-determined default allocations would be recorded by 120 days after 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 would be recorded by 30 days after the SIP submittal deadline. If a state submits a timely letter of intent followed by a timely SIP revision that is approved, the approved SIP allocations would be recorded by one year after publication of the final rule.

2. SIP Option To Modify Allocations in 2023 and Beyond

For the 2023 control period and later, EPA proposes that states in the CSAPR NOX Ozone Season Group 3 Trading Program can modify the EPA-determined default allocations with an approved SIP revision. EPA proposes that the SIP submittal deadline be December 1, 2021. The deadline for states to submit state-determined allocations for 2023 and 2024 under an approved SIP would be June 1, 2022, and the deadline for EPA to record those allocations would be July 1, 2022. Under the proposed new deadlines, a state could submit a SIP revision for 2025 and beyond control periods by December 1, 2022, with state allocations for the 2025 and 2026 control periods due June 1, 2023, and EPA recordation of the allocations by July 1, 2023. For the 2023 control period and later, SIPs could be full or abbreviated SIPs. As discussed in section VIII.F.3. below, states would 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, large non-EGU boilers and combustion turbines. Inclusion of the large non-EGUs would serve as a mechanism to address the state's outstanding regulatory obligations under the NOX SIP Call with respect to those sources, and the state would be allowed to allocate a defined quantity of additional Group 3 allowances because of the expanded set of sources. See above and 76 FR 48326-48332 for additional discussion on full and abbreviated SIP options and 40 CFR 52.38(b).

3. SIP Revisions that Do Not Use the New Group 3 Trading Program

States can submit SIP revisions to replace the FIP that achieve the necessary emission 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, 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 emission reductions (i.e., reductions equal to or greater than what the Group 3 trading program will achieve) will be achieved. In order to best ensure its approvability, the SIP revision should include the following general elements: (1) A comprehensive baseline 2021 statewide NOX emission inventory (which includes existing control requirements), which should be consistent with the 2021 emission inventory that EPA would use when finalizing this rulemaking to calculate the required state budget (unless the state can explain the discrepancy); (2) a list and description of control measures to satisfy the state emission reduction obligation and a demonstration showing when each measure would be in place to meet the 2021 and successive control periods; (3) fully-adopted state rules providing for such NOX controls during the ozone season; (4) for EGUs greater than 25 MWe, 40 CFR part 75 monitoring, 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 emission reductions in time to meet the 2021 compliance deadline. 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 a schedule and date for each affected source or source category to achieve compliance. Once the state has made a SIP submission, EPA will evaluate the submission(s) for completeness. 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).

4. Submitting a SIP To Participate in the New Group 3 Trading Program for States Not Included

Finally, EPA is also proposing to allow a state whose sources are required to participate in the CSAPR NOx Ozone Season Group 1 Trading Program (i.e., Georgia) or a state whose sources are required to continue to participate in the CSAPR NOx Ozone Season Group 2 Trading Program (as proposed, Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Tennessee, Texas, and Wisconsin) to submit a SIP revision to require its sources to participate instead in the new Group 3 trading program. A similar option was made available to Georgia in the CSAPR Update (with respect to the Group 2 trading program) to address possible concerns expressed by some commenters that if sources in Georgia were not allowed to trade with sources in other states, the allowances issued to the sources in Georgia would otherwise Start Printed Page 69025be of limited use. See 40 CFR 52.38(b)(6). The proposed option in this rulemaking, similar to the option created in the CSAPR Update, would require the state to adopt into its SIP a more stringent budget reflecting emission levels at higher dollar per ton emission reduction costs comparable to the dollar per ton emission reduction costs used to establish the budgets for states whose sources are proposed to be subject to the CSAPR NOX Ozone Season Group 3 Trading Program described in this proposal.

E. Title V Permitting

This proposed rule, like the CSAPR and the 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.[172] All major stationary sources of air pollution and certain other sources are required to apply for title V operating permits that include emission limitations and other conditions as necessary to assure 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”)).

EPA anticipates that, given the nature of the units subject to this proposed rule and given that all of the units proposed to be covered here are already subject to the CSAPR Update, 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 2008 ozone NAAQS that are applicable to them under the proposed 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 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 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 by the CSAPR and the 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 the CSAPR and the CSAPR Update, EPA established standard requirements governing how sources covered by that rule would comply with title V and its regulations.[173] 40 CFR 97.506(d) and 97.806(d). For any new or existing sources under this proposed rule establishing the Group 3 program, identical title V compliance provisions would apply, just as they would have in the CSAPR NOx Ozone Season Group 2 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 the CSAPR and the CSAPR Update, 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) and 97.806(d)(1). This provision is also included in each title V permit for an affected source. This proposed rule maintains the approach taken under the CSAPR and the 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 a CSAPR 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 the CSAPR and the CSAPR Update (i.e., approaches using a continuous emission 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) and 97.806(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 guidance, the Agency suggests in its template that sources may comply with this requirement by including a table of all of the approved monitoring and reporting approaches under the CSAPR and CSAPR Update trading programs in which the source is required to participate, and the applicable requirements governing each of those approaches. Inclusion of the 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 the CSAPR and the 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 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 EPA. These applications and petitions are subject to 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.[174] EPA maintains the same approach in this proposed rule.

Consistent with EPA's approach under the CSAPR and the CSAPR Update, the applicable requirements resulting from the proposed new and amended FIPs, if finalized, generally would 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)).[175] For sources newly subject to Start Printed Page 69026title V that are affected sources under the proposed 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 and the CSAPR Update, the proposed 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 and on permitting authorities.

F. Relationship to Other Emission Trading and Ozone Transport Programs

1. Existing Trading Programs

This proposed rule if adopted would end the requirements for sources in certain states to participate in the existing CSAPR NOx Ozone Season Group 2 Trading Program after the 2020 control period and require those same sources instead to participate in a new CSAPR NOx Ozone Season Group 3 Trading Program with more stringent emissions budgets. As discussed in section VIII.C.4. above, the proposal lays out certain requirements associated with this transition, including provisions to accommodate an effective date sometime after the start of the 2021 ozone season, conversion of certain banked 2017-2020 Group 2 allowances into a limited quantity of Group 3 allowances available for use in the new Group 3 trading program, and the recall of 2021-2024 Group 2 allowances previously allocated to the sources in Group 3 states. In addition, in section VIII.C.8. of this document, EPA describes certain features of the new Group 3 trading program that differ from the current features of the other CSAPR trading programs and that EPA proposes to adopt as revisions to the other CSAPR trading programs as well. A subset of those new features are also proposed to be adopted as revisions to the similarly structured Texas SO2 Trading Program. Beyond these items, nothing else in this rule affects any requirements for any source under the CSAPR NOX Annual, SO2 Group 1 or Group 2, or NOX Ozone Season Group 1 or Group 2 trading programs or the Texas SO2 Trading Program. These trading programs all remain in place and will continue to be administered by EPA.

2. Title IV Interactions

This proposed rule if adopted 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 Clean Air Act 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 at the end of a compliance year.

3. NOX SIP Call Interactions

States affected by both the NOX SIP Call and any final CSAPR ozone season requirements for the 2008 NAAQS will be required to comply with the requirements of both rules. This proposed rule requires NOX ozone season emission reductions from EGUs larger than 25 MWe in many NOX SIP Call states and at greater stringency than required by the NOX SIP Call. Therefore, this proposed rule would satisfy the requirements of the NOX SIP Call for these large EGUs.

The NOX SIP Call states used the NOX Budget Trading Program to comply with the NOX SIP Call requirements for EGUs serving generators with a nameplate capacity greater than 25 MWe and large non-EGU boilers and combustion turbines with a maximum design heat input greater than 250 mmBtu/hr. (In some states, EGUs serving a generator with a nameplate capacity equal to or smaller than 25 MWe were also part of the NOX Budget Trading Program as a carryover from the Ozone Transport Commission NOX Budget Program.) When EPA promulgated CAIR, it allowed states to modify that trading program and include all NOX Budget Trading Program units in the CAIR NOX Ozone Season Trading Program as a way to continue to meet the requirements of the NOX SIP Call for these sources.

In the CSAPR, however, EPA allowed states to expand applicability of the trading program to EGUs serving a generator with a nameplate capacity equal to or less than 25 MWe but did not allow the expansion of applicability to include large non-EGU sources. The reason for excluding large non-EGU sources was largely that emissions from these sources were generally much lower than the budget amount and there was concern that surplus allowances created as a result of an overestimation of baseline emissions and subsequent shutdowns (since 1999 when the NOX SIP Call was promulgated) would prevent needed reductions by the EGUs to address significant contribution to downwind air quality impacts.

Since then, states have had to find appropriate ways to continue to show compliance with the NOX SIP Call, particularly for large non-EGUs. Some states that included such sources in CAIR are still working to find suitable solutions.

Therefore, as in the CSAPR Update, EPA is proposing to allow any NOX SIP Call state affected by this proposed rule to voluntarily submit a SIP revision at a budget level that is environmentally neutral to address the state's NOX SIP Call requirement for ozone season NOX reductions from large non-EGUs. The SIP revision could include provisions to expand the applicability of the CSAPR NOX Ozone Season Group 3 Trading Program to include all NOX Budget Trading Program units. Analysis shows that these units (mainly large non-EGU boilers, combustion turbines, and combined cycle units with a maximum design heat input greater than 250 mmBtu/hr) continue to emit well below their portion of the NOX SIP Call budget. In order to ensure that the necessary amount of EGU emission reductions occur for this proposed rule, the corresponding state ozone-season emissions budget amount could be increased by the lesser of the highest ozone season NOX emissions (in the last 3 years) from those units or the relevant non-EGU budget under the NOX SIP Call, and this small group of non-EGUs could participate in the CSAPR NOX Ozone Season Group 3 Trading Program. The environmental impact would be neutral using this approach, and hourly reporting of emissions under 40 CFR part 75 would continue. This approach would address requests by states for help in determining an appropriate way to address the continuing NOX SIP Call requirement for large boilers and turbines. EPA proposes that if this SIP-based option is finalized, the variability limits established for EGUs under the CSAPR NOX Ozone Season Group 3 Trading Program would remain unchanged despite the inclusion of these non-EGUs. The assurance provisions established for the CSAPR NOX Ozone Season Trading Program would apply to EGUs, and emissions from non-EGUs would not affect the assurance levels.

The NOX SIP Call generally requires that states choosing to rely on large EGUs and large non-EGU boilers and turbines for meeting NOX SIP Call emission reduction requirements must establish a NOX mass emissions cap on each source and require 40 CFR part 75, subpart H monitoring or alternative monitoring. As an alternative to source-by-source NOX mass emission caps, a state may impose NOX emission rate limits on each source and use maximum operating capacity for estimating NOX mass emissions or may rely on other requirements that the state demonstrates Start Printed Page 69027to be equivalent to either the NOX mass emission caps or the NOX emission rate limits that assume maximum operating capacity. Collectively, the caps or their alternatives cannot exceed the portion of the state budget for those sources. See 40 CFR 51.121(f)(2) and (i)(4). If EPA were to allow a state to expand the applicability of this proposed rule to include all the NOX Budget Trading Program units in the CSAPR NOX Ozone Season Group 3 Trading Program, the cap requirement would be met through the new budget and the monitoring requirement would be met through the trading program provisions, which require part 75 monitoring. Whether the option for states to include NOX Budget Trading Program units in the CSAPR NOX Ozone Season Group 3 Trading Program through SIPs is finalized or not, EPA will work with states to ensure that NOX SIP Call obligations continue to be met. EPA requests comment on whether to authorize the states' voluntary inclusion of NOX SIP Call non-EGUs in the proposed Group 3 trading program (Comment C-40).

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

This proposed action is expected to reduce concentrations of both ground-level ozone and fine particles (PM2.5) (see discussion in Chapter 3 of the Regulatory Impact Analysis (RIA)). EPA historically has used conclusions of the most recent Integrated Science Assessment (ISA) to inform its approach for quantifying air pollution-attributable health, welfare, and environmental impacts associated with that pollutant. There is a separate ISA for each of the criteria pollutants. The ISA synthesizes the epidemiologic, controlled human exposure and experimental evidence “. . . useful in indicating the kind and extent of identifiable effects on public health or welfare which may be expected from the presence of [a] pollutant in ambient air.”

The ISA uses a weight of evidence approach to assess the extent the evidence supports conclusions about the likelihood that a given criteria pollutant causes a given health outcome. EPA generally estimates the number and economic value of the effects for which the ISA identifies the pollutant as having “causal” or “likely to be causal” relationship. The endpoints for which the 2020 final Ozone ISA [176] and the 2019 final PM ISA [177] identified as being causal or likely causal differed in some cases from the endpoints for which those pollutants were identified as being causal or likely causal in the Ozone and PM ISAs completed for the previous NAAQS reviews (see Tables 5-5 and 5-6 in Chapter 5 of the RIA). EPA traditionally uses the ISAs' characterizations of the health and ecological literature to identify individual studies that may be of sufficient quality for use in supporting PM or ozone benefits analysis.

When updating its approach for quantifying the benefits of changes in PM2.5 and Ozone, the Agency will incorporate evidence reported in these two recently completed ISAs and account for forthcoming recommendations from the Science Advisory Board on this issue. When updating the evidence for a given endpoint, EPA will consider the extent to which there is a causal relationship, whether suitable epidemiologic studies exist to allow quantification of concentration response functions, and whether there are robust economic approaches for estimating the value of the impact of reducing human exposure to the pollutant. Carefully and systematically reviewing the full breadth of this information requires significant time and resources. This process is still underway and will not be completed in time for this proposal. EPA intends to update its quantitative methods for estimating the number and economic value of PM2.5 and ozone health effects in time for publication as part of the final rule.[178] However, to provide perspective regarding the scope of the estimated benefits, Appendix 5B of the RIA illustrates the potential health effects associated with the change in PM2.5 and ozone concentrations as calculated using methods developed prior to the 2019 p.m. ISA and 2020 Ozone ISA. The values of these estimated benefits are not reflected in the estimated net benefits reported in Tables IX.4 and IX.5 below.

EPA estimated the compliance costs, emissions changes, and climate benefits that may result from the proposed rule for the years of analysis, 2021 to 2025. The estimated costs and climate benefits are presented in detail in the RIA accompanying this proposed action. EPA notes that the estimated compliance costs and climate benefits are directly associated with turning on or fully operating existing SCRs to achieve the assigned NOx emission rate, and installing state-of-the-art combustion controls. The estimated compliance costs and climate benefits also result from a small amount of generation shifting as the power system adjusts to the proposed regulatory requirements.

EPA analyzed this action's proposed emission budgets, which were developed using uniform control stringency represented by $1,600 per ton of NOX (2016$), as well as a more and a less stringent alternative. The more and less stringent alternatives differ in that they set different NOX ozone season emission budgets for the affected EGUs. The less stringent alternative uses emission budgets that were developed using uniform control stringency represented by $500 per ton of NOX (2016$). The more stringent alternative uses emission budgets that were developed using uniform control stringency represented by $9,600 per ton of NOX (2016$). Table IX.1 provides the projected 2021 and 2025 EGU emissions reductions for the evaluated regulatory control alternatives. For additional information on emissions changes in each year from 2021 through 2025, see Table 4.5 in Chapter 4 of the RIA.Start Printed Page 69028

Table IX.1—Estimated 2021 and 2025 a EGU Emissions Reductions in the 12 States of NOX, SO2, and CO2 and More and Less Stringent Alternatives

[Tons] b c

ProposalMore stringent alternativeLess stringent alternative
2021:
NOX (annual)17,00017,0002,000
NOX (ozone season)17,00017,0002,000
SO2 (annual)
CO2 (annual, thousand metric)
2025:
NOX (annual)27,00041,0002,000
NOX (ozone season)21,00035,0002,000
SO2 (annual)
CO2 (annual, thousand metric)4,00010,0003,000
a The 2021 emissions reductions estimates are based on IPM projections for 2021 and engineering analysis. For more information, see the Ozone Transport Policy Analysis TSD.
b NOX emissions are reported in English (short) tons; CO2 is reported in metric tons.
c In addition to no annual SO2 emissions reductions as shown in the table above, there are no annual direct PM2.5 emissions reductions.

EPA analyzed ozone-season NOX emission reductions and the associated costs to the power sector of implementing the EGU NOX ozone-season emissions budgets in each of the 12 states using the Integrated Planning Model (IPM) and its underlying data and inputs. The estimates of the changes in the cost of supplying electricity for the regulatory control alternatives are presented in Table IX.2.

Table IX.2—National Compliance Cost Estimates (Millions of 2016$) for the Regulatory Control Alternatives

ProposalMore-stringent alternativeLess-stringent alternative
2021-2025 (Annualized)19.480.61.6
2021 (Annual)20.937.23.8
2025 (Annual)6.3132.2−12.0
The 2021-2025 (Annualized) row reflects total estimated annual compliance costs levelized over the period 2021 through 2025, discounted using a 4.25 real discount rate. The 2021 (Annual) and 2025 (Annual) rows reflect annual estimates in each of those years.

EPA estimated the climate benefits for this proposed rulemaking using a measure of the domestic social cost of carbon (SC-CO2). Table IX.3 shows the estimated monetary value of the estimated changes in CO2 emissions in 2021 and 2025 for this proposed action, the more stringent alternative, and the less stringent alternative.

Table IX.3—Estimated Domestic Climate Benefits From Changes in CO2 Emissions for Selected Years

[Millions of 2016$]

Regulatory optionYear3% Discount rate7% Discount rate
Proposal20210.30.0
202532.95.4
More Stringent Alternative20210.80.1
202571.511.7
Less Stringent Alternative20210.20.0
202525.54.2

In Table IX.4, EPA presents a summary of the benefits, costs, and net benefits of this proposed action and the more and less stringent alternatives for 2021. Table IX.5 presents a summary of these impacts for this proposed action and the more and less stringent alternatives for 2025. EPA represents the present annual value of non-monetized benefits from ozone, PM2.5 and NO2 reductions as a B. The annual value of B will differ across discount rates, year of analysis, and the regulatory alternatives analyzed. Further discussion of the non-monetized health and welfare benefits from these pollutants is found in Chapter 5 of the RIA.Start Printed Page 69029

Table IX.4—Benefits, Costs, and Net Benefits of the Proposal and More and Less Stringent Alternatives for 2021 for the U.S.

[Millions of 2016$] a b c ,d

Discount rateBenefitsCostsNet benefits
Proposal:
3%0.31 + B21−21 + B
7%0.05 + B−21 + B
More Stringent Alternative:
3%0.80 + B37−36 + B
7%0.12 +B−37 + B
Less Stringent Alternative:
3%0.17 + B4−4 + B
7%0.03 + B−4 + B
a EPA focused results to provide a snapshot of costs and benefits in 2021, using the best available information to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
b Benefits ranges represent discounting of climate benefits at a real discount rate of 3 percent and 7 percent. Climate benefits are based on changes (reductions) in CO2 emissions. The costs presented in this table are 2021 annual estimates for each alternative analyzed.
c All costs and benefits are rounded to two significant figures; rows may not appear to add correctly.
d B is the sum of all unquantified ozone, PM2.5, and NO2 benefits. The annual value of B will differ across discount rates, year of analysis, and the regulatory alternatives analyzed. While EPA did not estimate these benefits in the RIA, Appendix 5B in the RIA presents PM2.5 and ozone estimates quantified using methods consistent with the previously published ISAs to provide information regarding the potential magnitude of the benefits of this proposed rule.

Table IX.5—Benefits, Costs, and Net Benefits of the Proposal and More and Less Stringent Alternatives for 2025 for the U.S.

[Millions of 2016$] a b c d

Discount rateBenefitsCostsNet benefits
Proposal:
3%33 + B627 + B
7%5.4 + B−0.9 + B
More Stringent Alternative:
3%71.5 + B132−61 + B
7%11.7 + B−120 + B
Less Stringent Alternative:
3%25 + B−1237 + B
7%4.2 + B16 + B
a EPA focused results to provide a snapshot of costs and benefits in 2025, using the best available information to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
b Benefits ranges represent discounting of climate benefits at a real discount rate of 3 percent and 7 percent. Climate benefits are based on changes (reductions) in CO2 emissions. The costs presented in this table are 2025 annual estimates for each alternative analyzed.
c All costs and benefits are rounded to two significant figures; rows may not appear to add correctly.
d B is the sum of all unquantified ozone, PM2.5, and NO2 benefits. The annual value of B will differ across discount rates, year of analysis, and the regulatory alternatives analyzed. While EPA did not estimate these benefits in the RIA, Appendix 5B in the RIA presents PM2.5 and ozone estimates quantified using methods consistent with the previously published ISAs to provide information regarding the potential magnitude of the benefits of this proposed rule.

In addition, Table IX-6 presents estimates of the present value (PV) of the 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 five-year period of 2021 to 2025. 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 2021. The table reflects the present value of non-monetized benefits from ozone, PM2.5 and NO2 reductions as a β, while b represents the equivalent annualized value of these non-monetized benefits. These values will differ across the discount rates and depend on the B's in Tables IX.4 and IX.5.

Table IX.6—Estimated Compliance Costs, Climate Benfits, and Net Benefits of the Proposed Rule, 2021 Through 2025

[Millions 2016$, discounted to 2021]

3% Discount rate7% Discount rate
Present Value:
Benefits c d101 + β15 + β
Climate Benefits c10115
Compliance Costs e8783
Net Benefits14 + β−68 + β
Equivalent Annualized Value:
Benefits22 + b4 + b
Climate Benefits224
Start Printed Page 69030
Compliance Costs1920
Net Benefits3 + b−17+ b
a All estimates in this table are rounded to two significant figures, so numbers may not sum due to independent rounding.
b The annualized present value of costs and benefits are calculated over a 5 year period from 2021 to 2025.
c Benefits ranges represent discounting of climate benefits at a real discount rate of 3 percent and 7 percent. Climate benefits are based on changes (reductions) in CO2 emissions.
d β and b is the sum of all unquantified ozone, PM2.5, and NO2 benefits. The annual values of β and b will differ across discount rates. While EPA did not estimate these benefits in the RIA, Appendix 5B in the RIA presents PM2.5 and ozone estimates quantified using methods consistent with the previously published ISAs to provide information regarding the potential magnitude of the benefits of this proposed rule.
e The costs presented in this table reflect annualized present value compliance costs calculated over a 5 year period from 2021 to 2025.

As shown in Table IX-6, the PV of the climate benefits of this proposed rule, discounted at a 7-percent rate, is estimated to be about $15 million, with an EAV of about $4 million. At a 3-percent discount rate, the PV of the climate benefits is estimated to be about $101 million, with an EAV of $22 million. The PV of the compliance costs, discounted at a 7-percent rate, is estimated to be about $83 million, with an EAV of about $20 million. At a 3-percent discount rate, the PV of the estimated compliance costs is about $87 million, with an EAV of about $19 million. The PV of the net benefits of this proposed rule, discounted at a 7-percent rate, is estimated to be about −$68 million, with an EAV of about −$17 million. At a 3-percent discount rate, the PV of net benefits is about $14 million, with an EAV of about $3 million. See the RIA for additional discussion on costs, benefits, and impacts.

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

This section describes the proposed amendments to the regulatory text for the federal implementation plans and the trading program regulations related to the proposed findings and remedy discussed elsewhere in this document. The primary amendments to the CFR would be revisions to the CSAPR Update FIP provisions in 40 CFR part 52 and the creation of a new CSAPR NOX Ozone Season Group 3 Trading Program in 40 CFR part 97, subpart GGGGG. In addition, amendments are proposed to the regulations for the existing CSAPR NOX Ozone Season Group 2 Trading Program to address the transition of the sources in certain states from the existing Group 2 program to the new Group 3 program. The existing regulations for the administrative appeal procedures in 40 CFR part 78 would also be revised to reflect the applicability of those procedures to decisions of the EPA Administrator under the new Group 3 trading program.

In addition to these primary amendments, certain revisions are proposed to the regulations for the existing CSAPR trading programs and the Texas SO2 Trading Program for conformity with the proposed provisions of the new Group 3 trading program, as discussed in section VIII.C.8. This section also describes a small number of minor additional proposed corrections and clarifications to the existing CFR text for the CSAPR trading programs, the Texas SO2 Trading Program, and the appeal procedures. EPA has included documents in the docket for this proposed action showing all of the proposed revisions to part 52, part 78, and subparts AAAAA through FFFFF of part 97 in redline-strikeout format.

A. Amended CSAPR Update FIP Provisions

The CSAPR and the CSAPR Update FIP provisions related to ozone season NOX emissions are set forth in § 52.38(b) as well as sections of part 52 specific to each covered state. Proposed amendments to § 52.38(b)(1) would expand the overall set of CSAPR trading programs addressing ozone season NOX emissions to include the new Group 3 trading program in subpart GGGGG of part 97 in addition to the current Group 1 and Group 2 trading programs in subparts BBBBB and EEEEE of part 97, respectively while proposed amendments to § 52.38(b)(2) would identify the states whose sources would be required under the new or amended FIPs to participate in each of the respective trading programs with regard to their emissions occurring in particular years. More specifically, for sources in the states that EPA proposes to find have further good neighbor obligations with respect to the 2008 ozone NAAQS under this rule, new § 52.38(b)(2)(iv) would end the requirement to participate in the Group 2 trading program after the 2020 control period and new § 52.38(b)(2)(v) would establish the requirement to participate in the new Group 3 trading program starting with the 2021 control period.

The changes in FIP requirements set forth in § 52.38(b)(1) and (2) would be replicated in the state-specific CFR sections for each of the Group 3 states.[179] In each such CFR section, the current provision indicating that sources in the state are required to participate in the CSAPR NOX Ozone Season Group 2 Trading Program would be revised to end that requirement with respect to emissions after 2020 and to restore previously removed language indicating that participation by those sources in the Group 2 trading program was only a partial remedy for the state's underlying good neighbor obligation.[180] A further provision would be added in each section 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 2021. These added provisions would not contain the partial-remedy language, consistent with EPA's proposed determinations in this rule that participation in the Group 3 trading program by a state's EGUs would constitute a full remedy for each such state's underlying good neighbor obligation. No changes would be made to the CFR sections for the remaining states whose sources currently participate in the Group 2 trading Start Printed Page 69031program. For these states, EPA's proposed findings in this action would be consistent with and would therefore affirm the previous removal of language indicating that participation by the states' sources in the Group 2 trading program was only a partial remedy for the states' underlying good neighbor obligations.[181]

As under the CSAPR and the CSAPR Update, states subject to the proposed FIPs under this rule would have several options to revise their SIPs to modify or replace those FIPs while continuing to use the Group 3 trading program as the mechanism for meeting the states' good neighbor obligations. New § 52.38(b)(11), (12), and (13) would 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 later years, respectively. The first two options would modify certain provisions of the trading program as applied to a state's sources but leave the FIP in place, while the third option would replace the FIP with largely identical SIP requirements for sources to participate in a state Group 3 trading program integrated with the federal Group 3 trading program. These options closely replicate the analogous current options in § 52.38(b)(7), (8) and (9) with regard to the Group 2 trading program. To make use of the option to submit state-determined allocations for the 2022 control period, a state would need to notify EPA by 90 days after publication of the final rule of its intent to submit to EPA by 180 days after publication a state-approved spreadsheet setting forth the allocations. To modify or replace the FIP with an abbreviated or full SIP affecting 2023 or 2024 allocations, the state would need to submit a SIP revision by December 1, 2021.

Like the analogous options under the Group 2 trading program, the abbreviated and full SIP options under the Group 3 trading program in new § 52.38(b)(12)(i) and (ii) and (b)(13)(i) and (ii) would include options for a state to expand applicability to include certain non-EGU boilers and combustion turbines or smaller EGUs in the state that were previously subject to the NOX Budget Trading Program. As discussed in section VIII.F.3 of this document, in conjunction with an expansion to include the non-EGUs, the state would be able to also issue an additional amount of allowances. Revised § 52.38(b)(14)(ii) [182] clarifies that a SIP revision requiring a state's sources—EGUs or non-EGUs—to participate in the Group 3 trading program would satisfy the state's obligations to adopt control measures for such sources under the NOX SIP Call.

The proposed option discussed in section VIII.D.4 of this preamble for a state whose EGUs currently are required to participate the Group 1 or Group 2 trading program to submit a full SIP revision requiring its sources to instead participate in the Group 3 program is set forth in new § 52.38(b)(10). This option would be generally similar to the full SIP option under new § 52.38(b)(13) for states whose sources are already subject to the Group 3 program under a FIP. To the extent that EPA had already commenced allocations of Group 1 or Group 2 allowances to sources in the state for future control periods, the Group 1 or Group 2 allowances already allocated for those control periods would be converted into Group 3 allowances under revised § 97.526(c)(2) or new § 97.826(c)(2).

The principal consequences of EPA's approval of a full SIP revision under § 52.38(b) would be set forth in § 52.38(14) and (15). Revised § 52.38(b)(14)(i) [183] would provide that—with exceptions indicated in other provisions of § 52.38(b)—full and unconditional approval of a state's full SIP revision under new § 52.38(b)(10) or (13) as correcting the SIP's deficiency that was the basis for a given FIP would cause the automatic withdrawal of the corresponding FIP requirements with regard to the sources in the state (except sources in Indian country with the borders of the state). New § 52.38(b)(15)(i), which addresses the Group 1 and Group 2 trading programs rather than the Group 3 trading program, identifies specific amended provisions of the federal trading Group 1 and Group 2 trading programs that would continue to apply to sources in a state Group 1 or Group 2 trading program implemented under a SIP provision in order to provide programmatic consistency across sources participating in the federal trading program and sources participating in integrated state trading programs. Revised § 52.38(b)(15)(ii),[184] which addresses the Group 3 trading program as well as the Group 1 and Group 2 trading programs, would preserve EPA's ability to complete allowance allocations for any control period where such allocations were already underway when the SIP revision was approved, Provisions indicating these consequences of approval of a full SIP revision would also be added to the state-specific CFR sections.

The transition between the Group 2 trading program and the Group 3 trading program, as well as the transition between the Group 1 trading program and the Group 2 trading program or Group 3 trading program, is addressed in § 52.38(b)(15)(iii), which identifies several allowance-related provisions of the federal trading program regulations that would continue to apply when the sources in a state transition to a different federal trading program (and also would continue to apply under an integrated state trading program). Revised § 52.38(b)(15)(iii)(A) [185] would preserve EPA's authority under § 97.526(c) to carry out conversions of Group 1 allowances to Group 3 allowances in all compliance accounts (as well as all general accounts) following the transition of a state's sources from the Group 1 trading program to the Group 3 trading program or following any SIP revision, adding to the provision's existing coverage with respect to conversions of Group 1 allowances to Group 2 allowances. New § 52.38(b)(15)(iii)(B) would preserve EPA's analogous authority under new § 97.826(c) with respect to conversions of Group 2 allowances to Group 3 allowances in analogous circumstances. New § 52.38(b)(15)(iii)(C) would similarly preserve EPA's authority under new § 97.811(d), concerning the proposed recall of Group 2 allowances allocated to sources in Group 3 states for control periods after 2020, following any SIP revision. For clarity, revisions to the state-specific CFR sections would replicate the provisions of § 52.38(b)(15)(iii) indicating that the provisions of §§ 97.526(c), 97.826(c), and 97.811(d) would continue to apply following the transition of a state's sources from one trading program to another or following approval any SIP revision under § 52.38(b).

New § 52.38(b)(17)(ii) would provide that, after the control period in 2020, EPA would stop administering all Group 2 trading program provisions established under SIP revisions previously approved for Group 2 states whose sources would be required to Start Printed Page 69032participate in the Group 3 program starting with the 2021 control period.[186]

Finally, new § 52.38(b)(18) would contain updatable lists of states with approved SIP revisions to modify or replace the FIP requirements for the Group 3 trading program, supplementing the analogous lists at § 52.38(b)(16) and (b)(17)(i) [187] for the Group 1 and Group 2 trading programs.

B. New CSAPR NOX Ozone Season Group 3 Trading Program Provisions

The proposed Group 3 trading program regulations would be promulgated in a new subpart GGGGG of part 97 (40 CFR 97.1001 through 97.1035). Definitions, applicability, standard requirements, and other general provisions would be set forth in §§ 97.1001 through 97.1008. State budgets and allocations of allowances to individual units would be addressed in §§ 97.1010 through 97.1012, and provisions concerning designated representatives would be covered in §§ 97.1013 through 97.1018. Management and use of allowances, including accounts, recordation, transfers, compliance, and banking, would be addressed in §§ 97.1020 through 97.1028. Provisions for monitoring, recordkeeping, and reporting would be set forth in §§ 97.1030 through 97.1035.

In general, the Group 3 trading program provisions would parallel the existing Group 2 trading program regulations in subpart EEEEE of part 97 but would reflect the amounts of the budgets, new unit set-asides, Indian country new unit set-asides, and variability limits established in this proposed rulemaking, all of which would be set forth in new § 97.1010. That same section would also set forth the amounts of the Group 3 budgets, new unit set-asides, and variability limits that Group 1 or Group 2 states could adopt in SIP revisions that would be approvable under new § 52.38(b)(10).

Under § 97.1006(c)(3)(i) and (ii), the obligations to hold one Group 3 allowance for each ton of emissions during the control period and to comply with the Group 3 trading program's assurance provisions would begin with the 2021 control period, four years later than the analogous start dates for the Group 2 trading program. The deadlines for certifying monitoring systems under § 97.1030(b) and for beginning quarterly reporting under § 97.1034(d)(1) similarly would be four years later than the analogous Group 2 trading program deadlines. The allowance recordation deadlines under § 97.1021 would begin generally four years later than the comparable recordation deadlines under the Group 2 trading program but would reach the same schedule by July 1, 2023, which would be the deadline for recordation of allowances for the control period in 2026 under both trading programs. However, under new § 97.1021(m), EPA would not record any allocations of Group 3 allowances to any unit at a source until all deductions of Group 2 allowances previously allocated to the units at the source for control periods after 2020 had been completed in accordance with new § 97.811(d).

Like the analogous Group 2 regulations, the Group 3 regulations would allow a Group 3 allowance that was allocated to any account as a replacement for removed Group 1 or Group 2 allowances to be used for all of the purposes for which any other Group 3 allowance may be used. This would be accomplished by adding references to §§ 97.526(c) and 97.826(c)—the sections under which the conversions would be carried out—to the definitions of “allocate” and “CSAPR NOX Ozone Season Group 3 allowance” in § 97.1002 as well as the default order for deducting allowances for compliance purposes under § 97.1024(c)(2).

Any Group 3 allowances allocated based on conversion of Group 1 or Group 2 allowances allocated for future years—specifically, the Group 3 allowances that could be allocated under § 97.526(c)(2) or § 97.826(c)(2) if EPA approved a SIP revision from a Group 1 or Group 2 state requiring sources in the state to participate in the Group 3 trading program—would also be treated like any other Group 3 allowance for purposes of determining shares of responsibility for exceedances under the assurance provisions. New paragraphs (2)(iii) and (iv) of the definition of “common designated representative's assurance level” in § 97.1002 would establish this equivalence. However, allocations of Group 3 allowances converted from banked Group 1 or Group 2 allowances would be excluded for purposes of determining such shares of responsibility because such converted allowances would not represent allowances allocated from the current control period's emissions budgets. This exclusion would be addressed in new paragraph (2)(ii) of the definition of “common designated representative's assurance level” in § 97.1002.

As is currently allowed under the Group 2 trading program, EPA has proposed that, in order to facilitate NOX SIP Call compliance, a state would be allowed to expand applicability of the Group 3 trading program to include any sources that previously participated in the NOX Budget Trading Program, and that the state would be able to issue an amount of allowances beyond the state's Group 3 trading program budget if applicability is expanded to include large non-EGU boilers and turbines. Again, like the Group 2 trading program, EPA has also proposed that the assurance provisions would apply only to emissions from the sources subject to the Group 3 trading program before any such expansion. Accordingly, the assurance provisions in the proposed Group 3 trading program regulations would exclude any additional units and allowances brought into the program through such a SIP revision. Specifically, the definitions of “base CSAPR NOX Ozone Season Group 3 unit” and “base CSAPR NOX Ozone Season Group 3 source” in § 97.1002 would exclude units and sources that would not have been included in the program under § 97.1004, and all provisions related to the Group 3 assurance provisions would reference only such “base” units and sources.

Proposed §§ 97.1016, 97.1018, and 97.1020(c)(1) and (5) would reduce the administrative compliance burden for sources in the transition from the Group 2 trading program to the Group 3 trading program by providing that certain one-time or periodic submissions made for purposes of compliance with the Group 1 or Group 2 trading program will be considered valid for purposes of the Group 3 trading program as well. The submissions treated in this manner are a certificate of representation or notice of delegation submitted by a designated representative and an application for a general account or notice of delegation submitted by an authorized account representative.

Finally, in conjunction with promulgation of the new Group 3 trading program, EPA has proposed to amend the administrative appeal provisions in part 78 to make the procedures of that part applicable to determinations of the EPA Administrator under the new Group 3 trading program in the same manner as the procedures are applicable to similar determinations under the other CSAPR trading programs and previous EPA trading programs. These amendments would add provisions for the Group 3 trading program to: The list in § 78.1(a)(1) of CFR sections (and analogous SIP revisions) generally giving rise to determinations subject to the part 78 procedures; the list in Start Printed Page 69033§ 78.1(b) of certain determinations that are expressly subject to those procedures; the list in § 78.3(a) of the types of persons who may seek review under the procedures; the list in § 78.3(b) of persons who must be served regarding an appeal; the list in § 78.3(c) of the required contents of petitions for review; the list in § 78.3(d) of matters for which a right of review under part 78 is not provided; and the requirements in § 78.4(a)(1) as to who must sign a filing.

C. Transitional Provisions

As discussed in section VIII.C.4., EPA has proposed to establish three sets of transitional provisions to address the transition of sources that currently participate in the CSAPR NOX Ozone Season Group 2 Trading Program but that, starting with the 2021 control period, would instead participate in the CSAPR NOX Ozone Season Group 3 Trading Program.

The first set of transitional provisions, which would be implemented at new § 97.811(d), would address the recall of Group 2 allowances previously allocated for control periods after 2020 to Group 3 sources (and other entities in Group 3 states).

The second set of transitional provisions would address the possibility that the effective date for the final action in this rulemaking would fall after May 1, 2021. In order to avoid application of the more stringent emission reduction requirements proposed in this action retroactively before the final rule's effective date, this set of provisions would make supplemental allocations of Group 3 allowances to Group 3 sources in amounts collectively equal to the differences in the respective states' budgets under the Group 2 and Group 3 trading programs for the portion of the 2021 ozone season occurring before that date. The total amounts of supplemental allowances for each state would be determined under new § 97.1010(d). The amount of the allocation to each Group 3 unit would be the incremental amount that each unit would have received if the supplemental allowances had been allocated as part of the respective state's emissions budget for 2021, using the same allocation methodology EPA proposes to apply to compute the allocations to existing units from the emissions budget, as set forth in new § 97.1011(a)(3). In addition, to avoid retroactive application of the more stringent Group 3 assurance levels associated with the more stringent Group 3 budgets before the final rule's effective date, the assurance levels for each Group 3 state for the 2021 control period would be increased by the product of 1.21 times the total amount of the supplemental allocations to the units in that state. The language implementing this provision is included in new § 97.1006(c)(2)(iii). New paragraph (2)(v) of the definition of “common designated representative's assurance level” in § 97.1002 includes language that accounts for the allocations of supplemental allowances and the increment to the variability limit when apportioning responsibility for any exceedance of a state's assurance level among the owners and operators of the state's sources.

The third set of transitional provisions would address conversions of Group 2 allowances (and in some instances Group 1 allowances) to Group 3 allowances for use in the new Group 3 program. These provisions would be implemented largely through the addition of new § 97.826(c) to the Group 2 trading program regulations and revisions to the analogous provisions in the Group 1 trading program regulations in 97.526(c). Most notably, the proposed one-time conversion of banked 2017-2020 Group 2 allowances to Group 3 allowances would be implemented through the provisions in new § 97.826(c)(1). These provisions set forth the schedule and mechanics for a default one-time conversion of Group 2 allowances that were allocated for the control periods in 2017 through 2020 and that that remain banked following the completion of deductions for compliance for the 2020 control period. The conversion would be applied to all banked Group 2 allowances that as of the scheduled conversion date are held in any general account and in any compliance account for a source located in a Group 3 state but would not be applied to allowances held in a compliance account for a source located in a Group 2 state. The owner or operator of a source located in a Group 2 state could retain banked Group 2 allowances for future use in the Group 2 trading program simply by keeping the allowances in the source's compliance account as of the conversion date or, alternatively, could elect to have banked Group 2 allowances converted to Group 3 allowances simply by transferring the allowances from the source's compliance account to a general account prior to the conversion date. The conversion factor would be the greater of 1.0000 or the ratio of the total number of banked Group 2 allowances being converted to the sum of the variability limits (adjusted to exclude any portion of the first ozone season before the final rule's effective date) for all states covered by the Group 3 trading program.

The proposed option under which the authorized account representative for a general account could elect to prevent certain Group 2 allowances from being included in the default conversion process would be implemented through the provisions in new § 97.826(c)(1)(iv). Under these provisions, before the scheduled date for converting Group 2 allowances to Group 3 allowances, EPA would establish a temporary holding account that would accept transfers of Group 2 allowances from general accounts. Any Group 2 allowances transferred to the temporary holding account in advance of the scheduled conversion date would not be converted to Group 3 allowances, and after completing the conversion procedures for other Group 2 allowances, EPA would transfer the unconverted Group 2 allowances back to the general accounts from which the transfers into the temporary holding account were made.

The additional conversion provisions in § 97.826(c)(2) and (3) would apply only in instances where a Group 2 state submits and EPA approves a SIP revision requiring sources in the state to participate in the Group 3 trading program. In that case, under § 97.826(c)(2), EPA would replace the allocations of Group 2 allowances to the state's sources already recorded for future control periods with allocations of Group 3 allowances, using a conversion factor determined based on the ratio of the state's emissions budget under the Group 2 trading program to the state's optional emissions budget under the Group 3 trading program. If all Group 2 states were to elect this option, following approval of the SIP submission for the last such state, under § 97.826(c)(3), EPA would convert any remaining banked Group 2 allowances from prior control periods using a conversion factor based on the ratio of the total number of Group 2 allowances being converted to that state's variability limit under the Group 3 program. Allowances would be converted under these provisions regardless of the accounts in which they were held.

Additional provisions of § 97.826(c) would address special circumstances. Under § 97.826(c)(4), if any Group 2 allowances are removed for conversion from the compliance account for a source in a state not covered by the Group 3 program, the owner or operator could identify to EPA a general account to receive the Group 3 allowances. This provision would be necessary in such circumstances because Group 3 allowances could not be recorded in any compliance account other than a compliance account for a source with a unit affected under the Group 3 trading program. If the owner or operator did not identify a general account to receive Start Printed Page 69034the Group 3 allowances within 180 days after the conversion, EPA would be authorized to retire the allowances. (The provisions in new § 97.826(c)(4) would not be used in the transition from the Group 2 trading program to the Group 3 trading program if, as proposed, sources in all existing Group 2 states are either transitioned to the Group 3 trading program or continue to be covered by the Group 2 trading program.)

Under § 97.826(c)(5), EPA would be able to group multiple general accounts under common ownership for purposes of performing conversion computations. Because allowances are only recorded as whole allowances, allowance conversion computations will necessarily be rounded to whole allowances. The purpose of the grouping provision would be to ensure that, given rounding, the total quantities of Group 3 allowances issued would not be unduly affected by how the Group 2 allowances are distributed across multiple general accounts under common ownership, with potentially adverse consequences to achievement of the emission reductions required under the rule.

There is a possibility under the Group 2 trading program that some new Group 2 allowances could be issued after the conversions to Group 3 allowances have already taken place. Under § 97.826(c)(6), EPA may convert these allowances to Group 3 allowances as if they had been issued and recorded before the general conversions.

Owners and operators of Group 3 sources generally would not be able to retain banked Group 2 allowances in the compliance accounts for those sources. However, new § 97.826(c)(7) would authorize the use of Group 3 allowances to satisfy obligations to hold Group 2 allowances that might arise after the conversion date, such as an obligation to hold additional allowances because of excess emissions or for compliance with the assurance provisions. When held for this purpose, a single Group 3 allowance could satisfy the obligation to hold more than one Group 2 allowance, as though the conversion were reversed. (As an alternative to using these provisions, the owners and operators of a Group 3 source could use Group 2 allowances held in a general account.)

Amendments addressing conversions of Group 1 allowances to Group 3 allowances in the event Georgia were to elect to join the Group 3 trading program would be reflected in proposed revisions to § 97.526(c)(2) through (7). The revisions would parallel the new provisions discussed above in § 97.826(c)(2) through (7), and in the case of 97.526(c)(4) would include changes making that provision more similar to new § 97.826(c)(4) in two ways. First, the provision would be simplified by requiring that the account identified to receive any otherwise unclaimed allowances must be a general account. Identification of another compliance account would no longer be allowed, making it possible to eliminate rule provisions distinguishing eligible compliance accounts from ineligible compliance accounts. (Any general account would be eligible.) Second, the provision would be modified to authorize the Administrator to retire any allowances that remain unclaimed 180 days after the conversion in question, or, if later, 90 days after the date of publication of a final rule in this action.

Finally, in § 78.1(b)(14) and (17), determinations of the EPA Administrator under §§ 97.526(c) and 97.826(c) regarding conversions of Group 1 and Group 2 allowances to Group 3 allowances and determinations of the EPA Administrator under § 97.811(d) regarding the recall of Group 2 allowances previously allocated to Group 3 units for control periods after 2020 would be added to the list of determinations expressly subject to the part 78 procedures.

D. Conforming Revisions, Corrections, and Clarifications To Existing Regulations

As discussed in section VIII.C.8, EPA has proposed several amendments to the existing CSAPR trading programs and the Texas SO2 Trading Program for conformity with the analogous provisions of the new Group 3 trading program.

The proposal to record allocations to existing units three instead of four years in advance of the control period at issue, starting with allocations for the 2025 control periods, would be implemented in the existing CSAPR trading programs through revisions to §§ 97.421(f), 97.521(f), 97.621(f), 97.721(f), and 97.821(f).

The proposal to switch from a two-round process to a one-round process for allocating allowances from new unit set-asides and Indian country new unit set-asides starting with the 2023 control periods would be implemented in the existing CSAPR trading programs through revisions to §§ 97.411(b), 97.511(b), 97.611(b), 97.711(b), and 97.811(b) and 97.412, 97.512, 97.612, 97.712, and 97.812. The changes to the deadlines for EPA to record the allocations determined through the proposed one-round process would be implemented through revisions to §§ 97.421(g) through (j), 97.521(g) through (j), 97.621(g) through (j), 97.721(g) through (j), and 97.821(g) through (j). The necessary coordinating revisions to dates included in the definitions of “allowance transfer deadline” and “common designated representative” would be made in §§ 97.402, 97.502, 97.602, 97.702, and 97.802. The proposed simplifications of the assurance provisions made possible by the changes in the new unit set-aside provisions would be implemented through revisions to §§ 97.425(b), 97.525(b), 97.625(b), 97.725(b), and 97.825(b). The related extensions to the deadlines for states with approved SIP revisions to submit to EPA any state-determined allowance allocations would be implemented through revisions to § 52.38(a)(4) and (5) and (b)(4), (5), (8) and (9) and § 52.39(e), (f), (h), and (i).

As discussed in section VIII.C.8., EPA has proposed to replicate several of the deadline revisions proposed for the existing CSAPR trading programs in the similarly structured Texas SO2 Trading Program in order to minimize unnecessary differences between the programs. These revisions to the Texas SO2 Trading Program regulations would be implemented at § 97.902 (definitions of “allowance transfer deadline” and “common designated representative”), 97.921(b) and (c), and 97.925(b).

The proposed amendments that would authorize EPA to reallocate any incorrectly allocated allowances through the new unit set-aside procedures for a control period after the correction is identified, instead of the new unit set-aside procedures for the control period for which the incorrect allocations were originally made, would be implemented in §§ 97.411(c)(5), 97.511(c)(5), 97.611(c)(5), 97.711(c)(5), and 97.811(c)(5).

The proposed amendments to correct the amounts of allowances in the new unit set-asides to address rounding differences from earlier amendments would be implemented in §§ 97.410, 97.510, 97.610, and 97.710.

New § 52.38(a)(7)(i) and (b)(15)(i) and § 52.39(k)(1) would identify the amended provisions that EPA proposes to implement in the existing state CSAPR trading programs to ensure consistent program implementation across all sources, whether the sources participate in the integrated trading programs under FIPs or approved SIP revisions.

EPA proposes to make additional, non-substantive corrections and clarifications in various provisions of the existing CSAPR trading programs in subparts AAAAA through EEEEE of part 97, the Texas SO2 Trading Program in Start Printed Page 69035subpart FFFFF of part 97, and the appeal procedures in part 78. The corrections and clarifications address minor typographical, wording, and formatting errors or update existing cross-references to reflect the new and redesignated provisions in §§ 52.38 and 52.39. In addition, the proposed corrections and clarifications include the following items:

  • Reorganization of the definitions of “common designated representative's assurance level” and “common designated representative's share” in §§ 97.402, 97.502, 97.602, 97.702, and 97.802. The revisions would clarify the definitions by relocating certain language between them, identifying provisions that would no longer apply after the control periods in 2023 because of the proposed revisions to the new unit set-aside allocation procedures, and correcting the omission of certain words in the terms “simple cycle combustion turbine” and “combined cycle combustion turbine”.
  • Addition of a definition of “CSAPR NOXOzone Season Group 3 allowance” in §§ 97.502 and 97.802 and addition of definitions of “CSAPR NOXOzone Season Group 3 Trading Program” and “nitrogen oxides” in §§ 97.402, 97.502, 97.602, 97.702, 97.802, and 97.902. The new definitions of terms for the Group 3 allowances and trading program are needed for other provisions that reference the Group 3 allowances or trading program, while the definition of nitrogen oxides corrects a current omission. Nitrogen oxides would be defined as “all oxides of nitrogen except nitrous oxide (N2 O), expressed on an equivalent molecular weight basis as nitrogen dioxide (NO2)”, which is consistent both with the definitions used in other EPA programs (see, e.g., 40 CFR 51.50, 51.121(a), and 51.122(a)) and with historical practice in the existing CSAPR programs.
  • Revisions to the descriptions of units and control periods eligible for allocations of allowances from the new unit set-asides and Indian country new unit set-asides in §§ 97.412, 97.512, 97.612, 97.712, and 97.812. The revisions would not substantively alter which units would receive allocations or the amounts of those allocations. Rather, the revisions would more clearly express the existing requirements of the allocation procedures, under which EPA calculates a given unit's allocations considering only the unit's emissions that occur after its deadline for monitor certification (because any earlier emissions would not have occurred in a “control period” for that unit).
  • Revisions to the provisions for identification of specific allowances to be deducted for compliance in §§ 97.424(c), 97.524(c), 97.624(c), 97.724(c), 97.824(c), and 97.924(c). The revisions would clarify by referencing designated representatives instead of authorized account representatives, consistent with the existing requirement that the authorized account representative for a source's compliance account must be the designated representative for the source.
  • Addition of references in part 78 to the Texas SO2Trading Program. The added references would be analogous to the references that would be added to part 78 for the proposed new Group 3 trading program. The applicability of the appeal procedures in part 78 to decisions of the EPA Administrator under the Texas SO2 Trading Program has already been established in the provisions for that trading program at § 97.908, but the addition of references in part 78 would clarify the regulations.

XI. Statutory and Executive Order Reviews

Additional information about these statutes and Executive Orders (“E.O.”) can be found at https://www.epa.gov/​laws-regulations/​laws-and-executive-orders.

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

This proposed action would be an economically significant regulatory action and was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. EPA prepared an analysis of the potential costs and benefits associated with this proposed action. This analysis, which is contained in the “Regulatory Impact Analysis for the Proposed Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS” [EPA-452/R-15-009], is available in the docket and is briefly summarized in Section IX of this preamble.

B. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs

This proposed action is expected to be an E.O. 13771 regulatory action. Details on the estimated costs of this proposed rule can be found in EPA's analysis of the potential costs and benefits associated with this action.

C. Paperwork Reduction Act (PRA)

This proposed action will not impose any new information collection burden under the PRA. This proposed action would relocate certain existing information collection requirements for certain sources from subpart EEEEE of 40 CFR part 97 to a new subpart GGGGG of 40 CFR part 97, but would neither change the inventory of sources subject to information collection requirements nor change any existing information collection requirements for any source. OMB has previously approved the information collection activities contained in the existing regulations and has assigned OMB control number 2060-0667.

D. Regulatory Flexibility Act (RFA)

I certify that this proposed action will not have a significant economic impact on a substantial number of small entities under the RFA. The small entities subject to the requirements of this proposed action are small businesses, small organizations, and small governmental jurisdictions.

EPA has lessened the impacts for small entities by excluding all units serving generators with capacities equal to or smaller than 25 MWe. This exclusion, in addition to the exemptions for cogeneration units and solid waste incineration units, eliminates the burden of higher costs for a substantial number of small entities located in the 12 states for which EPA is proposing FIPs. Within these states, EPA identified seven potentially affected EGUs that are owned by two entities that met the Small Business Administration's criteria for identifying small entities. Neither of these entities is projected to experience compliance costs that exceed 1 percent of generation revenues in 2021. EPA estimated the total net compliance cost to these two small entities to be approximately $0.04 million (in $2016).

EPA has concluded that there will be no significant economic impact on a substantial number of small entities (No SISNOSE) for this proposed rule. Details of this analysis are presented in the RIA, which is in the public docket.

E. 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 that we expect the proposal 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 proposal, such as employment effects in industries providing fuel and pollution control equipment, or the potential effects of electricity price Start Printed Page 69036increases on government entities. For more information on the estimated impact on government entities, refer to the RIA, which is in the public docket.

F. 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.

G. 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.

This action proposes to implement EGU NOX ozone season emissions reductions in 12 eastern states (Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.). However, at this time, none of the existing or planned EGUs affected by this rule are owned by tribes or located in Indian country. This proposed action may have tribal implications if a new affected EGU is built in Indian country. Additionally, tribes have a vested interest in how this proposed rule would affect air quality.

In developing the CSAPR, which was promulgated on July 6, 2011, to address interstate transport of ozone pollution under the 1997 ozone NAAQS, EPA consulted with tribal officials under the EPA Policy on Consultation and Coordination with Indian Tribes early in the process of developing that regulation to allow for meaningful and timely tribal input into its development. A summary of that consultation is provided at 76 FR 48346.

EPA received comments from several tribal commenters regarding the availability of the CSAPR allowance allocations to new units in Indian country. EPA responded to these comments by instituting Indian country new unit set-asides in the final CSAPR. In order to protect tribal sovereignty, these set-asides are managed and distributed by the federal government regardless of whether the CSAPR in the adjoining or surrounding state is implemented through a FIP or SIP. While there are no existing affected EGUs in Indian country covered by this proposal, the Indian country set-asides will ensure that any future new units built in Indian country will be able to obtain the necessary allowances. This proposal maintains the Indian country new unit set-aside and adjusts the amounts of allowances in each set-aside according to the same methodology of the CSAPR rule.

EPA informed tribes of our development of this proposal through a National Tribal Air Association—EPA air policy conference call on June 25, 2020. EPA plans to further consult with 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. EPA will facilitate this consultation before finalizing this proposed rule.

H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

This proposed action is not subject to E.O. 13045 because EPA does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. This action's health and risk assessments are contained in Chapter 5 of the accompanying RIA.

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

This proposal, which is a significant regulatory action under E.O. 12866, is likely to have a significant 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 much less than 1 percent change in retail electricity prices on average across the contiguous U.S. in 2021, and a much less than 1 percent reduction in coal-fired electricity generation in 2021 as a result of this rule. EPA projects that utility power sector delivered natural gas prices will change by less than 1 percent in 2021. For more information on the estimated energy effects, refer to the RIA, which is in the public docket.

J. National Technology Transfer and Advancement Act (NTTAA)

This proposed rulemaking does not involve technical standards.

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

EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income, or indigenous populations.

EPA notes that this action proposes to revise the CSAPR Update to reduce interstate ozone transport with respect to the 2008 ozone NAAQS. This rule uses EPA's authority in CAA section 110(a)(2)(d) (42 U.S.C. 7410(a)(2)(d)) to reduce NOX pollution that significantly contributes to downwind ozone nonattainment or maintenance areas. As a result, the rule will reduce exposures to ozone in the most-contaminated areas (i.e., areas that are not meeting the 2008 ozone NAAQS). In addition, the proposed rule separately identifies both nonattainment areas and maintenance areas. This requirement reduces the likelihood that areas close to the level of the standard will exceed the current health-based standards in the future. EPA proposes to implement these emission reductions using the CSAPR NOX Ozone Season Group 3 program with assurance provisions.

EPA recognizes that many environmental justice communities have voiced concerns in the past about emission trading and the potential for any emission increases in any location. The CSAPR NOX Ozone Season Group 3 Trading Program in the proposed action is the result of EPA's application of the 4-step framework to reduce interstate ozone pollution and implement those reductions, similar to the trading programs developed in the CSAPR (CSAPR NOX Ozone Season Group 1 Trading Program) and modified in the CSAPR Update (CSAPR NOX Ozone Season Group 2 Trading Program), both of which also resulted from the application of the 4-step framework. EPA believes that this approach used in the CSAPR and in the CSAPR Update mitigated community concerns about emissions trading, and that this proposal, which applies the same 4-step framework and proposes a trading program similar to those used in the CSAPR and the CSAPR Update, will also minimize community concerns. EPA seeks comment from communities on this proposal (Comment C-41).

Ozone pollution from power plants has both local and regional components: Part of the pollution in a given location—even in locations near emission sources—is due to emissions from nearby sources and part is due to emissions that travel hundreds of miles and mix with emissions from other sources.

It is important to note that the section of the Clean Air Act providing authority for this proposed rule, section 110(a)(2)(D) (42 U.S.C. 7410(a)(2)(D)), unlike some other provisions, does not Start Printed Page 69037dictate levels of control for particular facilities. In this proposed action, as in the CSAPR and the CSAPR Update, sources in the trading program may trade allowances with other sources in the same or different states, but any emissions shifting that may occur is constrained by an effective ceiling on emissions in each state (the assurance level). As in the CSAPR and the CSAPR Update, assurance provisions in the proposed rule outline the allowance surrender penalties for failing to meet the assurance level (see section VIII.C.2.); there are additional allowance for failing to hold an adequate number of allowances to cover emissions.

This approach will reduce EGU emissions in each state that significantly contributes to downwind nonattainment or maintenance areas with respect to the 2008 ozone NAAQS, while allowing power companies to adjust generation as needed and ensure that the country's electricity needs will continue to be met. As in the CSAPR and the CSAPR Update, EPA believes that the existence of these assurance provisions in the trading program, including the penalties imposed when triggered, will ensure that emissions from states covered by this proposal will stay below the level of the budget plus variability limit.

In addition, under this proposed rule all sources participating in the CSAPR NOX Ozone Season Group 3 Trading Program must hold enough allowances to cover their emissions. Therefore, if a source emits more than its allocation in a given year, either another source must have used less than its allocation and be willing to sell some of its excess allowances, or the source itself had emitted less than its allocation in one or more previous years (i.e., banked allowances for future use).

In summary, like the CSAPR and the CSAPR Update, this proposed rule minimizes community concerns about localized hot spots and reduces ambient concentrations of pollution where they are most needed by sensitive and vulnerable populations by: Considering the science of ozone transport to set strict state emissions budgets to reduce significant contributions to ozone nonattainment and maintenance (i.e., the most polluted) areas; implementing air quality-assured trading; requiring any emissions above the level of the allocations to be offset by emission decreases; and imposing strict penalties for sources that contribute to a state's exceedance of its budget plus variability limit. In addition, it is important to note that nothing in this proposed rule allows sources to violate their title V permit or any other federal, state, or local emissions or air quality requirements.

In addition, it is important to note that CAA section 110(a)(2)(D), which addresses transport of criteria pollutants between states, is only one of many provisions of the CAA that provide EPA, states, and local governments with authorities to reduce exposure to ozone in communities. These legal authorities work together to reduce exposure to these pollutants in communities, including for minority, low-income, and tribal populations, and provide substantial health benefits to both the general public and sensitive sub-populations.

EPA has already taken steps to begin informing communities of our development of this proposal through a National Tribal Air Association—EPA air policy conference call on June 25, 2020. EPA plans to further consult with communities early in the process of developing this regulation to permit them to have meaningful and timely input into its development. EPA will facilitate this engagement before finalizing this proposed rule.

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

Section 307(b)(1) of the CAA indicates which federal courts of appeals have venue for petitions of review of final actions by EPA. This section provides, in part, that petitions for review must be filed in the D.C. Circuit if (i) the Agency action consists of “nationally applicable regulations promulgated, or final action taken, by the Administrator,” or (ii) such action is locally or regionally applicable, if “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.” EPA anticipates that final action related to this proposed rulemaking will be “nationally applicable” and of “nationwide scope and effect” within the meaning of CAA section 307(b)(1). Through this rulemaking action, EPA interprets section 110 of the CAA, a provision which has nationwide applicability, and thus it appears that the final action would be based on a determination of nationwide scope and effect. In addition, the rule would apply to 21 States. Also, the rule would be based on a common core of factual findings and analyses concerning the transport of 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. For these reasons, the Administrator proposes to determine that this proposed action is of nationwide scope and effect for purposes of CAA section 307(b)(1). If the Administrator makes this proposed determination final, then pursuant to CAA section 307(b) any petitions for review of any final actions regarding the rulemaking would be filed in the D.C. Circuit within 60 days from the date any final action is published in the Federal Register.

In addition, pursuant to sections 307(d)(1)(B) and 307(d)(1)(V) of the CAA, the Administrator determines that all aspects of this proposed action are 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). Under CAA section 307(d)(1)(V), the provisions of section 307(d) also apply to “such other actions as the Administrator may determine.” 42 U.S.C. 7407(d)(1)(V). The Agency will comply with the procedural requirements of CAA section 307(d) in this rulemaking.

Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS

Start List of Subjects

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 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
End List of Subjects Start Signature

Dated: October 15, 2020.

Andrew Wheeler,

Administrator.

End Signature

For the reasons stated in the preamble, EPA proposes to amend parts 52, 78, and 97 of title 40 of the Code of Federal Regulations as follows:

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PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

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

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Subpart A—General Provisions

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2. Amend § 52.38 by:

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a. Revising the paragraph (a) subject heading;

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b. In paragraph (a)(1), adding a subject heading and removing “(NO X).” and adding in its place “(NOX), except as otherwise provided in this section.”;

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c. Adding a subject heading to paragraph (a)(2);

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d. Adding a subject heading to paragraph (a)(3) introductory text and removing “Notwithstanding the provisions of paragraph (a)(1) of this section, a State” and adding in its place “A State”;

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e. Revising paragraph (a)(4) introductory text;

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f. In paragraph (a)(4)(i)(A), removing the period at the end of the paragraph and adding in its place a semicolon;

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g. In paragraph (a)(4)(i)(B), removing “the following dates:” and adding in its place “the dates in Table 1 to this paragraph (a)(4)(i)(B);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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h. In paragraph (a)(4)(i)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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i. Adding a subject heading to paragraph (a)(5) introductory text and removing “Notwithstanding the provisions of paragraph (a)(1) of this section, a State” and adding in its place “A State”;

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j. In paragraph (a)(5)(i)(A), removing the period at the end of the paragraph and adding in its place a semicolon;

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k. In paragraph (a)(5)(i)(B), removing “the following dates:” and adding in its place “the dates in Table 2 to this paragraph (a)(5)(i)(B);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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l. In paragraph (a)(5)(i)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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m. In paragraph (a)(5)(v), adding “and” after the semicolon at the end of the paragraph;

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n. Adding a subject heading to paragraph (a)(6) and removing “Following promulgation” and adding in its place “Except as provided in paragraph (a)(7) of this section, following promulgation”;

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o. Revising paragraph (a)(7);

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p. Adding a subject heading to paragraph (a)(8) introductory text;

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q. Revising the paragraph (b) subject heading;

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r. Revising paragraph (b)(1);

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s. Adding a subject heading to paragraph (b)(2);

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t. In paragraph (b)(2)(ii), removing “2016 only:” and adding in its place “2016 only, except as provided in paragraph (b)(15)(iii) of this section:”;

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u. Revising paragraph (b)(2)(iii);

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v. Adding paragraphs (b)(2)(iv) and (v);

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w. Adding a subject heading to paragraph (b)(3) introductory text and removing “Notwithstanding the provisions of paragraph (b)(1) of this section, a State” and adding in its place “A State”;

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x. Revising paragraph (b)(4) introductory text;

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y. In paragraph (b)(4)(ii)(A), removing the period at the end of the paragraph and adding in its place a semicolon;

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z. In paragraph (b)(4)(ii)(B), removing “the following dates:” and adding in its place “the dates in Table 3 to this paragraph (b)(4)(ii)(B);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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aa. In paragraph (b)(4)(ii)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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bb. Adding a subject heading to paragraph (b)(5) introductory text and removing “Notwithstanding the provisions of paragraph (b)(1) of this section, a State” and adding in its place “A State”;

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cc. In paragraph (b)(5)(ii)(A), removing the period at the end of the paragraph and adding in its place a semicolon;

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dd. In paragraph (b)(5)(ii)(B), removing “the following dates:” and adding in its place “the dates in Table 4 to this paragraph (b)(5)(ii)(B);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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ee. In paragraph (b)(5)(ii)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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ff. In paragraph (b)(5)(vi), adding “and” after the semicolon at the end of the paragraph;

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gg. Adding a subject heading to paragraph (b)(6) introductory text and removing “Notwithstanding the provisions of paragraph (b)(1) of this section, a State” and adding in its place “A State”;

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hh. In paragraph (b)(6)(i), removing “SIP revision.” and adding in its place “SIP revision; and”;

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ii. Revising paragraph (b)(6)(ii);

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jj. Adding a subject heading to paragraph (b)(7) introductory text, removing “Notwithstanding the provisions of paragraph (b)(1) of this section, a State” and adding in its place “A State”, and adding “or (iv)” after “(b)(2)(iii)”;

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kk. Revising paragraphs (b)(8) introductory text and (b)(8)(ii);

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ll. In paragraph (b)(8)(iii)(A)(2), removing the period at the end of the paragraph and adding in its place a semicolon;

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mm. In paragraph (b)(8)(iii)(B), removing “the following dates:” and adding in its place “the dates in Table 5 to this paragraph (b)(8)(iii)(B);”, adding a heading to the table, and revising the table entry for “2025 and any year thereafter”;

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nn. In paragraph (b)(8)(iii)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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oo. Adding a subject heading to paragraph (b)(9) introductory text, removing “Notwithstanding the provisions of paragraph (b)(1) of this section, a State” and adding in its place “A State”, and adding “or (iv)” after “(b)(2)(iii)” wherever “(b)(2)(iii)” appears;

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pp. Revising paragraph (b)(9)(ii);

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qq. In paragraph (b)(9)(iii)(A)(2), removing the period at the end of the paragraph and adding in its place a semicolon;

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rr. In paragraph (b)(9)(iii)(B), removing “the following dates:” and adding in its place “the dates in Table 6 to this paragraph (b)(9)(iii)(B);”, adding a heading to the table, and Start Printed Page 69039revising the table entry for “2025 and any year thereafter”;

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ss. In paragraph (b)(9)(iii)(C), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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tt. In paragraph (b)(9)(vii), adding “and” after the semicolon at the end of the paragraph;

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uu. Revising paragraphs (b)(10) and (11);

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vv. Redesignating paragraphs (b)(12) and (13) as paragraphs (b)(16) and (17), respectively, and adding new paragraphs (b)(12) through (15), and further redesignating newly redesignated paragraphs (b)(17) introductory text and (b)(17)(i) through (iv) as paragraphs (b)(17)(i) introductory text and (b)(17)(i)(A) through (D), respectively;

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ww. Adding a subject headings to newly redesignated paragraphs (b)(16) introductory text and (b)(17) introductory text;

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xx. In newly redesignated paragraph (b)(17)(i)(D), adding “or (iv)” after “(b)(2)(iii)”; and

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yy. Adding paragraphs (b)(17)(ii) and (b)(18).

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The additions and revisions read as follows:

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) NOXannual emissions—(1) General requirements. * * *

(2) Applicability of CSAPR NOXAnnual Trading Program provisions. * * *

* * * * *

(3) State-determined allocations of CSAPR NOXAnnual allowances for 2016. * * *

* * * * *

(4) Abbreviated SIP revisions replacing certain provisions of the federal CSAPR NOXAnnual Trading Program. A State listed in paragraph (a)(2)(i) of this section may adopt and include in a SIP revision, and the Administrator will approve, regulations replacing specified provisions of subpart AAAAA of part 97 of this chapter for purposes of the State's sources, and not substantively replacing any other provisions, as follows:

(i) * * *

(B) * * *

Table 1 to Paragraph (a)(4)(i)(B)

Year of the control period for which CSAPR NOX Annual allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(5) Full SIP revisions adopting State CSAPR NOXAnnual Trading Programs. * * *

(i) * * *

(B) * * *

Table 2 to Paragraph (a)(5)(i)(B)

Year of the control period for which CSAPR NOX Annual allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(6) Withdrawal of CSAPR FIP provisions relating to NOXannual emissions. * * *

(7) Continued applicability of certain federal trading program provisions for NO Xannual emissions. (i) Notwithstanding the provisions of paragraph (a)(6) of this section or any State's SIP, when carrying out the functions of the Administrator under any State CSAPR NOX Annual Trading Program pursuant to a SIP revision approved under this section, the Administrator will apply the following provisions of this section, as amended, and the following provisions of subpart AAAAA of part 97 of this chapter, as amended, with regard to the State and any source subject to such State trading program:

(A) The definitions in § 97.402 of this chapter;

(B) The provisions in § 97.410(a) of this chapter concerning the amounts of the new unit set-asides;

(C) The provisions in §§ 97.411(b)(1) and 97.412(a) of this chapter concerning the procedures for allocating CSAPR NOX Annual allowances from new unit set-asides (except where the State allocates or auctions such allowances under an approved SIP revision);

(D) The provisions in § 97.411(c)(5) of this chapter concerning the disposition of incorrectly allocated CSAPR NOX Annual allowances;

(E) The provisions in § 97.421(f), (g), and (i) of this chapter concerning the deadlines for recordation of CSAPR NOX Annual allowances allocated in accordance with § 97.411(a) or § 97.412(a) of this chapter or allocated or auctioned under an approved SIP revision and the provisions in paragraphs (a)(4)(i)(B) and (C) and (a)(5)(i)(B) and (C) of this section concerning the deadlines for submission to the Administrator of State-determined allocations or auction results; and

(F) The provisions in § 97.425(b) of this chapter concerning the procedures for administering the assurance provisions.

(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 Start Printed Page 69040Administrator 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 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 units in the State for each such control period shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

(8) States with approved SIP revisions addressing the CSAPR NOXAnnual Trading Program. * * *

* * * * *

(b) NOXozone season emissions—(1) General requirements. The CSAPR NOX Ozone Season Group 1 Trading Program provisions, the CSAPR NOX Ozone Season Group 2 Trading Program provisions, and the CSAPR NOX Ozone Season Group 3 Trading Program provisions set forth respectively in subparts BBBBB, EEEEE, and GGGGG of part 97 of this chapter constitute the CSAPR 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), except as otherwise provided in this section.

(2) Applicability of CSAPR NOXOzone Season Group 1, Group 2, and Group 3 Trading Program provisions. * * *

* * * * *

(iii) 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 and each subsequent year: Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Tennessee, Texas, and Wisconsin.

(iv) 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, 2018, 2019, and 2020 only, except as provided in paragraph (b)(15)(iii) of this section: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.

(v) 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 2021 and each subsequent year: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.

(3) State-determined allocations of CSAPR NOXOzone Season Group 1 allowances for 2016. * * *

* * * * *

(4) Abbreviated SIP revisions replacing certain provisions of the federal CSAPR NOXOzone Season Group 1 Trading Program. A State listed in paragraph (b)(2)(i) 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's sources, 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 auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(5) Full SIP revisions adopting State CSAPR NOXOzone Season Group 1 Trading Programs. * * *

* * * * *

(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 auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(6) Full SIP revisions to voluntarily join the CSAPR NOXOzone Season Group 2 Trading Program. * * *

* * * * *

(ii) Following promulgation of an approval by the Administrator of such a SIP revision, the provisions of the SIP revision will apply to sources in the State with regard to emissions occurring in the control period that begins May 1 immediately after promulgation of such approval, or such later control period as may be adopted by the State in its regulations and approved by the Administrator in the SIP revision, and in each subsequent control period, except as provided in paragraph (b)(15) of this section.

(7) State-determined allocations of CSAPR NOX Ozone Season Group 2 allowances for 2018. * * *

* * * * *

(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)(iii) or (iv) of this section may adopt and include in a SIP revision, and the Administrator will Start Printed Page 69041approve, regulations replacing specified provisions of subpart EEEEE of part 97 of this chapter for the State's sources, and not substantively replacing any other provisions, as follows:

* * * * *

(ii) The State may adopt, as applicability provisions replacing the provisions in § 97.804(a) and (b) of this chapter with regard to the State, provisions substantively identical to those provisions, except that applicability is expanded to include all other units (beyond any units to which applicability could be expanded under paragraph (b)(8)(i) of this section) that would have been subject to any emissions trading program regulations approved as a SIP revision for the State under § 51.121 of this chapter; and

(iii) * * *

(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 auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(9) Full SIP revisions adopting State CSAPR NOX Ozone Season Group 2 Trading Programs. * * *

* * * * *

(ii) May adopt, as applicability provisions replacing the provisions in § 97.804(a) and (b) of this chapter with regard to the State, provisions substantively identical to those provisions, except that applicability is expanded to include all other units (beyond any units to which applicability could be expanded under paragraph (b)(9)(i) of this section) that would have been subject to any emissions trading program regulations approved as a SIP revision for the State under § 51.121 of this chapter;

(iii) * * *

(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 auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(10) Full SIP revisions to voluntarily join the CSAPR NOX Ozone Season Group 3 Trading Program. A State listed in paragraph (b)(2)(i) or (iii) of this section may adopt and include in a SIP revision, and the Administrator will approve, as correcting the deficiency in the SIP that is the basis for the CSAPR Federal Implementation Plan set forth in paragraphs (b)(1), (b)(2)(i), and (b)(3) and (4) of this section or paragraphs (b)(1), (b)(2)(iii), and (b)(7) and (8) of this section, as applicable, with regard to sources in the State (but not sources in any Indian country within the borders of the State), 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, subject to the following requirements and exceptions:

(i) The provisions of paragraphs (b)(13)(i) through (viii) of this section apply to any such SIP revision; and

(ii) Following promulgation of an approval by the Administrator of such a SIP revision, the provisions of the SIP revision will apply to sources in the State with regard to emissions occurring in the control period that begins May 1 immediately after promulgation of such approval, or such later control period as may be adopted by the State in its regulations and approved by the Administrator in the SIP revision, and in each subsequent control period, except as provided in paragraph (b)(15) of this section.

(11) State-determined allocations of CSAPR NOX Ozone Season Group 3 allowances for 2022. A State listed in paragraph (b)(2)(v) 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) of this chapter with regard to the State and the control period in 2022, 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 commenced commercial operation before January 1, 2019;

(ii) The total amount of CSAPR NOX Ozone Season Group 3 allowance allocations on the list must not exceed the amount, under § 97.1010(a) of this chapter for the State and the control period in 2022, of the CSAPR NOX Ozone Season Group 3 trading budget minus the sum of the new unit set-aside and Indian country new unit set-aside;

(iii) The list must be submitted electronically in a format specified by the Administrator; and

(iv) The SIP revision must not provide for any change in the units and allocations on the list after approval of the SIP revision by the Administrator and must not provide for any change in any allocation determined and recorded by the Administrator under subpart GGGGG of part 97 of this chapter;

(v) Provided that:

(A) By [DATE 60 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], 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)(11)(i) through (iv) of this section by [DATE 180 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]; andStart Printed Page 69042

(B) The State must submit to the Administrator a complete SIP revision described in paragraph (b)(11)(v)(A) of this section by [DATE 180 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].

(12) Abbreviated SIP revisions replacing certain provisions of the federal CSAPR NOX Ozone Season Group 3 Trading Program. A State listed in paragraph (b)(2)(v) 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's sources, and not substantively replacing any other provisions, as follows:

(i) The State may adopt, as applicability provisions replacing the provisions in § 97.1004(a)(1) and (2) of this chapter with regard to the State, provisions substantively identical to those provisions, except that the words “more than 25 MWe” are replaced, wherever such words appear, by words specifying a uniform lower limit on the amount of megawatts that is not greater than the amount specified by the words “more than 25 MWe” and is not less than the amount specified by the words “15 MWe or more”;

(ii) The State may adopt, as applicability provisions replacing the provisions in § 97.1004(a) and (b) of this chapter with regard to the State, provisions substantively identical to those provisions, except that applicability is expanded to include all other units (beyond any units to which applicability could be expanded under paragraph (b)(12)(i) of this section) that would have been subject to any emissions trading program regulations approved as a SIP revision for the State under § 51.121 of this chapter; and

(iii) The State may adopt, as CSAPR NOX Ozone Season Group 3 allowance allocation or auction provisions replacing the provisions in §§ 97.1011(a) and (b)(1) and 97.1012(a) of this chapter with regard to the State and the control period in 2023 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(a) and 97.1021 of this chapter for the State and such control period, of the CSAPR NOX Ozone Season Group 3 trading budget minus the sum of the Indian country new 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:

(1) The highest of the sum, for all additional units in the State to which applicability is expanded pursuant to paragraph (b)(12)(ii) of this section, of the NOX emissions reported in accordance with part 75 of this chapter for the ozone season in the year before the year of the submission deadline for the SIP revision under paragraph (b)(12)(iv) of this section and the corresponding sums of the NOX emissions reported in accordance with part 75 of this chapter for each of the two immediately preceding ozone seasons, provided that each such seasonal sum shall exclude the amount of any NOX emissions reported by any unit for all hours in any calendar day during which the unit did not have at least one quality-assured monitor operating hour, as defined in § 72.2 of this chapter; or

(2) The portion of the emissions budget under the State's emissions trading program regulations approved as a SIP revision under § 51.121 of this chapter that is attributable to the units to which applicability is expanded pursuant to paragraph (b)(12)(ii) of this section;

(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) of this chapter, that the State or the permitting authority submit such allocations or the results of such auctions for such control period (except allocations or results of auctions to such units of CSAPR NOX Ozone Season Group 3 allowances remaining in a set-aside after completion of the allocations or auctions for which the set-aside was created) to the Administrator no later than the dates in Table 7 to this paragraph (b)(12)(iii)(B);

Table 7 to Paragraph (b)(12)(iii)(B)

Year of the control period for which CSAPR NOX Ozone Season Group 3 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
2023June 1, 2022.
2024June 1, 2022.
2025June 1, 2023.
2026June 1, 2023.
2027 and any year thereafterJune 1 of the third year before the year of the control period.

(C) 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(b)(1) and 97.1012(a) of this chapter, that the State or the permitting authority submit such allocations or the results of such auctions (except allocations or results of auctions to such units of CSAPR NOX Ozone Season Group 3 allowances remaining in a set-aside after completion of the allocations or auctions for which the set-aside was created) to the Administrator by April 1 of the year following the year of such control period; and

(D) Does not provide for any change, after the submission deadlines in paragraphs (b)(12)(iii)(B) and (C) 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, § 97.526(c) of this chapter, or § 97.826(c) of this chapter;

(iv) Provided that the State must submit a complete SIP revision meeting the requirements of paragraph (b)(12)(i), (ii), or (iii) of this section by December Start Printed Page 690431 of the year before the year of the deadlines for submission of allocations or auction results under paragraphs (b)(12)(iii)(B) and (C) of this section applicable to the first control period for which the State wants to replace the applicability provisions, make allocations, or hold an auction under paragraph (b)(12)(i), (ii), or (iii) of this section.

(13) Full SIP revisions adopting State CSAPR NOXOzone Season Group 3 Trading Programs. A State listed in paragraph (b)(2)(v) 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)(v), and (b)(11) and (12) of this section with regard to sources in the State (but not sources in any Indian country within the borders of the State), 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:

(i) May adopt, as applicability provisions replacing the provisions in § 97.1004(a)(1) and (2) of this chapter with regard to the State, provisions substantively identical to those provisions, except that the words “more than 25 MWe” are replaced, wherever such words appear, by words specifying a uniform lower limit on the amount of megawatts that is not greater than the amount specified by the words “more than 25 MWe” and is not less than the amount specified by the words “15 MWe or more”;

(ii) May adopt, as applicability provisions replacing the provisions in § 97.1004(a) and (b) of this chapter with regard to the State, provisions substantively identical to those provisions, except that applicability is expanded to include all other units (beyond any units to which applicability could be expanded under paragraph (b)(13)(i) of this section) that would have been subject to any emissions trading program regulations approved as a SIP revision for the State under § 51.121 of this chapter;

(iii) May adopt, as CSAPR NOX Ozone Season Group 3 allowance allocation provisions replacing the provisions in §§ 97.1011(a) and (b)(1) and 97.1012(a) of this chapter with regard to the State and the control period in 2023 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(a) and 97.1021 of this chapter for the State and such control period, of the CSAPR NOX Ozone Season Group 3 trading budget minus the sum of the Indian country new 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)(13)(ii) of this section, an additional amount of CSAPR NOX Ozone Season Group 3 allowances not exceeding the lesser of:

(1) The highest of the sum, for all additional units in the State to which applicability is expanded pursuant to paragraph (b)(13)(ii) of this section, of the NOX emissions reported in accordance with part 75 of this chapter for the ozone season in the year before the year of the submission deadline for the SIP revision under paragraph (b)(13)(viii) of this section and the corresponding sums of the NOX emissions reported in accordance with part 75 of this chapter for each of the two immediately preceding ozone seasons, provided that each such seasonal sum shall exclude the amount of any NOX emissions reported by any unit for all hours in any calendar day during which the unit did not have at least one quality-assured monitor operating hour, as defined in § 72.2 of this chapter; or

(2) The portion of the emissions budget under the State's emissions trading program regulations approved as a SIP revision under § 51.121 of this chapter that is attributable to the units to which applicability is expanded pursuant to paragraph (b)(13)(ii) of this section;

(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) of this chapter, that the State or the permitting authority submit such allocations or the results of such auctions for such control period (except allocations or results of auctions to such units of CSAPR NOX Ozone Season Group 3 allowances remaining in a set-aside after completion of the allocations or auctions for which the set-aside was created) to the Administrator no later than the dates in Table 8 to this paragraph (b)(13)(iii)(B);

Table 8 to Paragraph (b)(13)(iii)(B)

Year of the control period for which CSAPR NOX Ozone Season Group 3 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
2023June 1, 2022.
2024June 1, 2022.
2025June 1, 2023.
2026June 1, 2023.
2027 and any year thereafterJune 1 of the third year before the year of the control period.

(C) 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(b)(1) and 97.1012(a) of this chapter, that the State or the permitting authority submit such allocations or the results of such auctions (except allocations or results of auctions to such units of CSAPR NOX Ozone Season Group 3 allowances remaining in a set-aside after completion of the allocations or auctions for which the set-aside was created) to the Administrator by April 1 of the year following the year of such control period; and

(D) Does not provide for any change, after the submission deadlines in paragraphs (b)(13)(iii)(B) and (C) 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, § 97.526(c) of this chapter, or § 97.826(c) of this chapter;Start Printed Page 69044

(iv) 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 CSAPR NOX Ozone Season Group 3 allowance allocation or auction provisions adopted under paragraph (b)(13)(iii) of this section;

(v) May substitute the name of the State for the term “State” as used in subpart GGGGG of part 97 of this chapter, to the extent the Administrator determines that such substitutions do not make substantive changes in the provisions in §§ 97.1002 through 97.1035 of this chapter; and

(vi) Must not include any of the requirements imposed on any unit in Indian country within the borders of the State in the provisions in §§ 97.1002 through 97.1035 of this chapter and must not include the provisions in §§ 97.1011(b)(2) and (c)(5)(iii), 97.1012(b), and 97.1021(h) and (j) of this chapter, all of which provisions will continue to apply under any portion of the CSAPR Federal Implementation Plan that is not replaced by the SIP revision;

(vii) Provided that, if and when any covered unit is located in Indian country within the borders of the State, the Administrator may modify his or her approval of the SIP revision to 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 may modify any portion of the CSAPR Federal Implementation Plan that is not replaced by the SIP revision to include these provisions; and

(viii) Provided that the State must submit a complete SIP revision meeting the requirements of paragraphs (b)(13)(i) through (vi) of this section by December 1 of the year before the year of the deadlines for submission of allocations or auction results under paragraphs (b)(13)(iii)(B) and (C) of this section applicable to the first control period for which the State wants to replace the applicability provisions, make allocations, or hold an auction under paragraph (b)(13)(i), (ii), or (iii) of this section.

(14) Withdrawal of CSAPR FIP provisions relating to NOXozone season emissions. 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)(iii) or (iv), and (b)(7) and (8) of this section, or paragraphs (b)(1), (b)(2)(v), and (b)(11) and (12) of this section for sources in the State—

(i) Except as provided in paragraph (b)(15) of this section, the provisions of paragraph (b)(2)(i), (iii), (iv), or (v) of this section, as applicable, will no longer apply to sources in the State, unless the Administrator's approval of the SIP revision is partial or conditional, and will continue to apply to sources in any Indian country within the borders of the State, 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

(ii) For a State listed in § 51.121(c) of this chapter, the State's adoption of the regulations included in such approved SIP revision will satisfy with regard to the sources subject to such regulations, including any sources made subject to such regulations pursuant to paragraph (b)(9)(ii) or (b)(13)(ii) of this section, the requirement under § 51.121(r)(2) of this chapter for the State to revise its SIP to adopt control measures with regard to such sources, provided that the Administrator and the State continue to carry out their respective functions under such regulations.

(15) Continued applicability of certain federal trading program provisions for NOXozone season emissions. (i) Notwithstanding the provisions of paragraph (b)(14)(i) of this section or any State's SIP, when carrying out the functions of the Administrator under any State CSAPR NOX Ozone Season Group 1 Trading Program or State CSAPR NOX Ozone Season Group 2 Trading Program pursuant to a SIP revision approved under this section, the Administrator will apply the following provisions of this section, as amended, and the following provisions of subpart BBBBB of part 97 of this chapter, as amended, or subpart EEEEE of part 97 of this chapter, as amended, with regard to the State and any source subject to such State trading program:

(A) The definitions in § 97.502 of this chapter or § 97.802 of this chapter;

(B) The provisions in § 97.510(a) of this chapter concerning the amounts of the new unit set-asides;

(C) The provisions in §§ 97.511(b)(1) and 97.512(a) of this chapter or §§ 97.811(b)(1) and 97.812(a) of this chapter concerning the procedures for allocating CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances from new unit set-asides (except where the State allocates or auctions such allowances under an approved SIP revision);

(D) The provisions in § 97.511(c)(5) of this chapter or § 97.811(c)(5) of this chapter concerning the disposition of incorrectly allocated CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances;

(E) The provisions in § 97.521(f), (g), and (i) of this chapter or § 97.821(f), (g), and (i) of this chapter concerning the deadlines for recordation of CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances allocated in accordance with § 97.511(a) or § 97.512(a) of this chapter or § 97.811(a) or § 97.812(a) of this chapter or allocated or auctioned under an approved SIP revision and the provisions in paragraphs (b)(4)(ii)(B) and (C) and (b)(5)(ii)(B) and (C) of this section or paragraphs (b)(8)(iii)(B) and (C) and (b)(9)(iii)(B) and (C) of this section concerning the deadlines for submission to the Administrator of State-determined allocations or auction results; and

(F) The provisions in § 97.525(b) of this chapter or § 97.825(b) of this chapter concerning the procedures for administering the assurance provisions.

(ii) Notwithstanding the provisions of paragraph (b)(6)(ii), (b)(10)(ii), or (b)(14)(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 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 units in the State for each such control period, including the provisions of §§ 97.526(c) and 97.826(c) of this chapter, shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

(iii) Notwithstanding any discontinuation of the applicability of other provisions of subpart BBBBB or EEEEE of part 97 of this chapter to the sources in a State pursuant to paragraph Start Printed Page 69045(b)(2)(ii) or (iv) or (b)(14)(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 allocated to or held by any source or other entity in the State and to all sources or other entities, wherever located, that received or at any time hold such allowances:

(A) The provisions of § 97.526(c)(1) through (6) of this chapter authorizing the Administrator to remove CSAPR NOX Ozone Season Group 1 allowances from any Allowance Management System account where such CSAPR NOX Ozone Season Group 1 allowances are held and to allocate and record amounts of CSAPR NOX Ozone Season Group 2 allowances or CSAPR NOX Ozone Season Group 3 allowances in place of any CSAPR NOX Ozone Season Group 1 allowances that have been so removed or that have not been initially recorded, and the provisions of § 97.526(c)(7) of this chapter authorizing the use of CSAPR NOX Ozone Season Group 2 allowances or CSAPR NOX Ozone Season Group 3 allowances to satisfy requirements to hold CSAPR NOX Ozone Season Group 1 allowances;

(B) The provisions of § 97.826(c)(1) through (6) of this chapter authorizing the Administrator to remove CSAPR NOX Ozone Season Group 2 allowances from any Allowance Management System account where such CSAPR NOX Ozone Season Group 2 allowances are held and to allocate and record amounts of CSAPR NOX Ozone Season Group 3 allowances in place of any CSAPR NOX Ozone Season Group 2 allowances that have been so removed or that have not been initially recorded, and the provisions of § 97.826(c)(7) of this chapter authorizing the use of CSAPR NOX Ozone Season Group 3 allowances to satisfy requirements to hold CSAPR NOX Ozone Season Group 2 allowances; and

(C) The provisions of § 97.811(d) of this chapter recalling all allocations of CSAPR NOX Ozone Season Group 2 allowances for control periods after 2020 to sources and other entities in States listed in paragraph (b)(2)(iv) of this section, requiring such sources and other entities to surrender of equal amounts of CSAPR NOX Ozone Season Group 2 allowances allocated for the same control periods to accomplish such recalls, authorizing the Administrator to record the removal of such surrendered CSAPR NOX Ozone Season Group 2 allowances from any Allowance Management Account, and establishing potential remedies for any failure to comply with such surrender requirements.

(16) States with approved SIP revisions addressing the CSAPR NOXOzone Season Group 1 Trading Program. * * *

* * * * *

(17) States with approved SIP revisions addressing the CSAPR NOXOzone Season Group 2 Trading Program. * * *

* * * * *

(ii) 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)(iv) of this section and any control period that begins after December 31, 2020, 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(d) and 97.826(c) 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.

(18) States with approved SIP revisions addressing the CSAPR NOXOzone Season Group 3 Trading Program. The following States have SIP revisions approved by the Administrator under paragraph (b)(10), (11), (12), or (13) of this section:

(i) For each of the following States, the Administrator has approved a SIP revision under paragraph (b)(10) 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)(i), and (b)(3) and (4) of this section or paragraphs (b)(1), (b)(2)(iii), and (b)(7) and (8) of this section with regard to sources in the State (but not sources in any Indian country within the borders of the State): [none].

(ii) For each of the following States, the Administrator has approved a SIP revision under paragraph (b)(11) of this section as replacing the CSAPR NOX Ozone Season Group 3 allowance allocation provisions in § 97.1011(a) of this chapter with regard to the State and the control period in 2022: [none].

(iii) For each of the following States, the Administrator has approved a SIP revision under paragraph (b)(12) 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) and (b)(1) and 97.1012(a) of this chapter with regard to the State and the control period in 2023 or any subsequent year: [none].

(iv) For each of the following States, the Administrator has approved a SIP revision under paragraph (b)(13) 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)(v), and (b)(11) and (12) of this section with regard to sources in the State (but not sources in any Indian country within the borders of the State): [none].

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3. Amend § 52.39 by:

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a. Adding a subject heading to paragraph (a) and removing “(SO 2).” and adding in its place “(SO2), except as otherwise provided in this section.”;

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b. Adding a subject heading to paragraph (b);

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c. Adding a subject heading to paragraph (c);

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d. Adding a subject heading to paragraph (d) introductory text and removing “Notwithstanding the provisions of paragraph (a) of this section, a State” and adding in its place “A State”;

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e. Revising paragraph (e) introductory text;

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f. In paragraph (e)(1)(i), removing the period at the end of the paragraph and adding in its place a semicolon;

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g. In paragraph (e)(1)(ii), removing “the following dates:” and adding in its place “the dates in Table 1 to this paragraph (e)(1)(ii);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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h. In paragraph (e)(1)(iii), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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i. Adding a subject heading to paragraph (f) introductory text and removing “Notwithstanding the provisions of paragraph (a) of this section, a State” and adding in its place “A State”;

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j. In paragraph (f)(1)(i), removing the period at the end of the paragraph and adding in its place a semicolon;

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k. In paragraph (f)(1)(ii), removing “the following dates:” and adding in its place “the dates in Table 2 to this paragraph (f)(1)(ii);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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l. In paragraph (f)(1)(iii), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the Start Printed Page 69046control period, for a control period in 2023 or thereafter; and”;

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m. In paragraph (f)(5), adding “and” after the semicolon at the end of the paragraph;

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n. Adding a subject heading to paragraph (g) introductory text and removing “Notwithstanding the provisions of paragraph (a) of this section, a State” and adding in its place “A State”;

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o. Revising paragraph (h) introductory text;

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p. In paragraph (h)(1)(i), removing the period at the end of the paragraph and adding in its place a semicolon;

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q. In paragraph (h)(1)(ii), removing “the following dates:” and adding in its place “the dates in Table 3 to this paragraph (h)(1)(ii);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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r. In paragraph (h)(1)(iii), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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s. Adding a subject heading to paragraph (i) introductory text and removing “Notwithstanding the provisions of paragraph (a) of this section, a State” and adding in its place “A State”;

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t. In paragraph (i)(1)(i), removing the period at the end of the paragraph and adding in its place a semicolon;

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u. In paragraph (i)(1)(ii), removing “the following dates:” and adding in its place “the dates in Table 4 to this paragraph (i)(1)(ii);”, adding a heading to the table, removing the table entry for “2023 and any year thereafter”, and adding table entries for “2023 and 2024” and “2025 and any year thereafter”;

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v. In paragraph (i)(1)(iii), removing “year of such control period.” and adding in its place “year of such control period, for a control period before 2023, or by April 1 of the year following the control period, for a control period in 2023 or thereafter; and”;

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w. In paragraph (i)(5), adding “and” after the semicolon at the end of the paragraph;

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x. Adding a subject heading to paragraph (j) and removing “Following promulgation” and adding in its place “Except as provided in paragraph (k) of this section, following promulgation”;

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y. Revising paragraph (k); and

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z. Adding a subject headings to paragraphs (l) introductory text and (m) introductory text.

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The additions and revisions read as follows:

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

(a) General requirements for SO2emissions. * * *

(b) Applicability of CSAPR SO2Group 1 Trading Program provisions. * * *

(c) Applicability of CSAPR SO2Group 2 Trading Program provisions. * * *

* * * * *

(d) State-determined allocations of CSAPR SO2Group 1 allowances for 2016. * * *

* * * * *

(e) Abbreviated SIP revisions replacing certain provisions of the federal CSAPR SO2Group 1 Trading Program. A State listed in paragraph (b) of this section may adopt and include in a SIP revision, and the Administrator will approve, regulations replacing specified provisions of subpart CCCCC of part 97 of this chapter for the State's sources, and not substantively replacing any other provisions, as follows:

(1) * * *

(ii) * * *

Table 1 to Paragraph (e)(1)(ii)

Year of the control period for which CSAPR SO2 Group 1 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(f) Full SIP revisions adopting State CSAPR SO2Group 1 Trading Programs. * * *

(1) * * *

(ii) * * *

Table 2 to Paragraph (f)(1)(ii)

Year of the control period for which CSAPR SO2 Group 1 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(g) State-determined allocations of CSAPR SO2Group 2 allowances for 2016. * * *

* * * * *

(h) Abbreviated SIP revisions replacing certain provisions of the federal CSAPR SO2Group 2 Trading Program. A State listed in paragraph (c)(1) of this section may adopt and include in a SIP revision, and the Administrator will approve, regulations replacing specified provisions of subpart DDDDD of part 97 of this chapter for the State's sources, and not substantively replacing any other provisions, as follows:

(1) * * *

(ii) * * *Start Printed Page 69047

Table 3 to Paragraph (h)(1)(ii)

Year of the control period for which CSAPR SO2 Group 2 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(i) Full SIP revisions adopting State CSAPR SO2Group 2 Trading Programs. * * *

(1) * * *

(ii) * * *

Table 4 to Paragraph (i)(1)(ii)

Year of the control period for which CSAPR SO2 Group 2 allowances are allocated or auctionedDeadline for submission of allocations or auction results to the Administrator
*         *         *         *         *         *         *
2023 and 2024June 1 of the fourth year before the year of the control period.
2025 and any year thereafterJune 1 of the third year before the year of the control period.
* * * * *

(j) Withdrawal of CSAPR FIP provisions relating to SO2emissions. * * *

(k) Continued applicability of certain federal trading program provisions for SO2emissions. (1) Notwithstanding the provisions of paragraph (j) of this section or any State's SIP, when carrying out the functions of the Administrator under any State CSAPR SO2 Group 1 Trading Program or State CSAPR SO2 Group 2 Trading Program pursuant to a SIP revision approved under this section, the Administrator will apply the following provisions of this section, as amended, and the following provisions of subpart CCCCC of part 97 of this chapter, as amended, or subpart DDDDD of part 97 of this chapter, as amended, with regard to the State and any source subject to such State trading program:

(i) The definitions in § 97.602 of this chapter or § 97.702 of this chapter;

(ii) The provisions in § 97.610(a) of this chapter or § 97.710(a) of this chapter concerning the amounts of the new unit set-asides;

(iii) The provisions in §§ 97.611(b)(1) and 97.612(a) of this chapter or §§ 97.711(b)(1) and 97.712(a) of this chapter concerning the procedures for allocating CSAPR SO2 Group 1 allowances or CSAPR SO2 Group 2 allowances from new unit set-asides (except where the State allocates or auctions such allowances under an approved SIP revision);

(iv) The provisions in § 97.611(c)(5) of this chapter or § 97.711(c)(5) of this chapter concerning the disposition of incorrectly allocated CSAPR SO2 Group 1 allowances or CSAPR SO2 Group 2 allowances;

(v) The provisions in § 97.621(f), (g) and (i) of this chapter or § 97.721(f), (g) and (i) of this chapter concerning the deadlines for recordation of CSAPR SO2 Group 1 allowances or CSAPR SO2 Group 2 allowances allocated in accordance with § 97.611(a) or § 97.612(a) of this chapter or § 97.711(a) or § 97.712(a) of this chapter or allocated or auctioned under an approved SIP revision and the provisions in paragraphs (e)(1)(ii) and (iii) and (f)(1)(ii) and (iii) of this section or paragraphs (h)(1)(ii) and (iii) and (i)(1)(ii) and (iii) of this section concerning the deadlines for submission to the Administrator of State-determined allocations or auction results; and

(vi) The provisions in § 97.625(b) of this chapter or § 97.725(b) of this chapter concerning the procedures for administering the assurance provisions.

(2) Notwithstanding the provisions of paragraph (i) of this section, if, at the time of an 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 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 units in the State for each such control period shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

(l) States with approved SIP revisions addressing the CSAPR SO2Group 1 Trading Program. * * *

* * * * *

(m) States with approved SIP revisions addressing the CSAPR SO2Group 2 Trading Program. * * *

* * * * *

Subpart O—Illinois

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4. Amend § 52.731 by revising paragraphs (b)(2) and (3) and adding paragraph (b)(4) to read as follows:

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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 Illinois 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, 2018, 2019, and 2020. The obligation to comply with such requirements will be eliminated by the promulgation of an approval by the Administrator of a revision to Illinois' 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)(iv), except to the extent the Administrator's approval is partial or conditional, provided that because the CSAPR FIP was Start Printed Page 69048promulgated 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.

(3) The owner and operator of each source and each unit located in the State of Illinois 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 2021 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 Illinois' 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)(v), 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, the provisions of §§ 97.526(c), 97.826(c), and 97.811(d) of this chapter shall apply with respect to each source or other entity located in the State and all CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances at any time allocated to or held by any such source or other entity. Further, if, at the time of the approval of Illinois' 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 units in the State for each such control period shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

Subpart P—Indiana

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5. Amend § 52.789 by revising paragraphs (b)(2) and (3) and adding paragraph (b)(4) to read as follows:

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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 Indiana 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, 2018, 2019, and 2020. The obligation to comply with such requirements will be eliminated by the promulgation of an approval by the Administrator of a revision to Indiana'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)(iv), except to the extent the Administrator's approval is partial or conditional, provided that because the CSAPR FIP 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.

(3) The owner and operator of each source and each unit located in the State of Indiana 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 2021 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 Indiana'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)(v), 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, the provisions of §§ 97.526(c), 97.826(c), and 97.811(d) of this chapter shall apply with respect to each source or other entity located in the State and all CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances at any time allocated to or held by any such source or other entity. Further, if, at the time of the approval of Indiana'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 of 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 units in the State for each such control period shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

Subpart S—Kentucky

Start Amendment Part

6. Amend § 52.940 by revising paragraphs (b)(2) and (3) and adding paragraph (b)(4) to read as follows:

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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 Kentucky 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, 2018, 2019, and 2020. The obligation to comply with such requirements will be eliminated by the promulgation of an approval by the Administrator of a revision to Kentucky'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)(iv), except to the extent the Administrator's approval is partial or conditional, provided that because the CSAPR FIP 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.

(3) The owner and operator of each source and each unit located in the State of Kentucky 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 2021 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 Kentucky'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)(v), except to the Start Printed Page 69049extent the Administrator's approval is partial or conditional.

(4) Notwithstanding the provisions of paragraphs (b)(2) and (3) of this section, the provisions of §§ 97.526(c), 97.826(c), and 97.811(d) of this chapter shall apply with respect to each source or other entity located in the State and all CSAPR NOX Ozone Season Group 1 allowances or CSAPR NOX Ozone Season Group 2 allowances at any time allocated to or held by any such source or other entity. Further, if, at the time of the approval of Kentucky'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 units in the State for each such control period shall continue to apply, unless provided otherwise by such approval of the State's SIP revision.

Subpart T—Louisiana

Start Amendment Part

7. Amend § 52.984 by revising paragraphs (d)(2) and (3) and adding paragraph (d)(4) to read as follows:

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

(d) * * *

(2) The owner and operator of each source and each unit located in the State of Louisiana 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, 2018, 2019, and 2020. The obligation to comply with such requirements with regard to sources and units in the State 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)(iv) for those sources and units, except to the extent the Administrator's approval is partial or conditional, provided that because the CSAPR FIP 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. The obligation to comply with such requirements with regard to sources and units located in Indian country within the borders of the State will not be eliminated by the promulgation of an approval by the Administrator of a revision to Louisiana's SIP.

(3) The owner and operator of each source and each unit located in the State of Louisiana 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 2021 and each subsequent year. The obligation to comply with such requirements with regard to sources and units in the State 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 de