New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule

Federal RegisterMay 23, 2023

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2023-0072; FRL-8536-02-OAR]

RIN 2060-AV09

New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

In this document, the Environmental Protection Agency (EPA) is proposing five separate actions under section 111 of the Clean Air Act (CAA) addressing greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units (EGUs). The EPA is proposing revised new source performance standards (NSPS), first for GHG emissions from new fossil fuel-fired stationary combustion turbine EGUs and second for GHG emissions from fossil fuel-fired steam generating units that undertake a large modification, based upon the 8-year review required by the CAA. Third, the EPA is proposing emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs. Fourth, the EPA is proposing emission guidelines for GHG emissions from the largest, most frequently operated existing stationary combustion turbines and is soliciting comment on approaches for emission guidelines for GHG emissions for the remainder of the existing combustion turbine category. Finally, the EPA is proposing to repeal the Affordable Clean Energy (ACE) Rule.

DATES:

Comments

. Comments must be received on or before July 24, 2023. Comments on the information collection provisions submitted to the Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA) are best assured of consideration by OMB if OMB receives a copy of your comments on or before June 22, 2023.

Public Hearing.

The EPA will hold a virtual public hearing on June 13, 2023 and June 14, 2023. See

SUPPLEMENTARY INFORMATION

for information on registering for a public hearing.

ADDRESSES:

You may send comments, identified by Docket ID No. EPA-HQ-OAR-2023-0072, by any of the following methods:

•

Federal eRulemaking Portal: https://www.regulations.gov

(our preferred method). Follow the online instructions for submitting comments.

•

Email: a-and-r-docket@epa.gov.

Include Docket ID No. EPA-HQ-OAR-2023-0072 in the subject line of the message.

•

Fax:

(202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-2023-0072.

•

Mail:

U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2023-0072, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.

•

Hand/Courier Delivery:

EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-Friday (except Federal holidays).

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

SUPPLEMENTARY INFORMATION

section of this document.

FOR FURTHER INFORMATION CONTACT:

For questions about these proposed actions, contact Mr. Christian Fellner, Sector Policies and Programs Division (D243-02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-4003; and email address:

fellner.christian@epa.gov

or Ms. Lisa Thompson, Sector Policies and Programs Division (D243-02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-9775; and email address:

thompson.lisa@epa.gov.

SUPPLEMENTARY INFORMATION:

Participation in virtual public hearing.

The public hearing will be held via virtual platform on June 13, 2023 and June 14, 2023 and will convene at 11:00 a.m. Eastern Time (ET) and conclude at 7:00 p.m. ET each day. If the EPA receives a high volume of registrations for the public hearing, the EPA may continue the public hearing on June 15, 2023. On each hearing day, the EPA may close a session 15 minutes after the last pre-registered speaker has testified if there are no additional speakers. The EPA will announce further details at

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

The EPA will begin pre-registering speakers for the hearing no later than 1 business day following the publication of this document in the

Federal Register

. The EPA will accept registrations on an individual basis. To register to speak at the virtual hearing, please use the online registration form available at

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power

or contact the public hearing team at (888) 372-8699 or by email at

SPPDpublichearing@epa.gov.

The last day to pre-register to speak at the hearing will be June 6, 2023. Prior to the hearing, the EPA will post a general agenda that will list pre-registered speakers in approximate order at:

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule.

Each commenter will have 4 minutes to provide oral testimony. The EPA encourages commenters to provide the EPA with a copy of their oral testimony by submitting the text of your oral testimony as written comments to the rulemaking docket.

The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral testimony 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/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

While the EPA expects the hearing to go forward as described in this section, please monitor our website or contact the public hearing team at (888) 372-8699 or by email at

SPPDpublichearing@epa.gov

to determine if there are any updates. The EPA does not intend to publish a document in the

Federal Register

announcing updates.

If you require the services of an interpreter or a special accommodation such as audio description, please pre-register for the hearing with the public hearing team and describe your needs by May 30, 2023. The EPA may not be able to arrange accommodations without advanced notice.

Docket.

The EPA has established a docket for these rulemakings under Docket ID No. EPA-HQ-OAR-2023-0072. All documents in the docket are listed in the

Regulations.gov

index. Although listed in the index, some information is not publicly available,

e.g.,

Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy.

Written Comments.

Direct your comments to Docket ID No. EPA-HQ-OAR-2023-0072 at

https://www.regulations.gov

(our preferred method), or the other methods identified in the

ADDRESSES

section. Once submitted, comments cannot be edited or removed from the docket. The EPA may publish any comment received to its public docket. Do not submit to the 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. This type of information should be submitted as discussed in the

Submitting CBI

section of this document.

Multimedia submissions (audio, video,

etc.

) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (

i.e.,

on the Web, cloud, or other file sharing system). Please visit

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

for additional submission methods; the full EPA public comment policy; information about CBI or multimedia submissions; and general guidance on making effective comments.

The

https://www.regulations.gov

website allows you to submit your comment anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through

https://www.regulations.gov,

your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and should be free of any defects or viruses.

Submitting CBI.

Do not submit information containing CBI to the EPA through

https://www.regulations.gov.

Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, note the docket ID, mark the outside of the digital storage media as CBI, and identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in

Written Comments

section of this document. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI and note the docket ID. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2.

Our preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol (FTP), or other online file sharing services (

e.g.,

Dropbox, OneDrive, Google Drive). Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address

oaqpscbi@epa.gov

and, as described above, should include clear CBI markings and note the docket ID. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email

oaqpscbi@epa.gov

to request a file transfer link. If sending CBI information through the postal service, please send it to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2023-0072. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.

Preamble acronyms and abbreviations.

Throughout this document the use of “we,” “us,” or “our” is intended to refer to the EPA. The EPA uses multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here:

ACE Affordable Clean Energy rule

BACT best available control technology

BSER best system of emissions reduction

Btu British thermal unit

CAA Clean Air Act

CBI Confidential Business Information

CCS carbon capture and sequestration/storage

CCUS carbon capture, utilization, and sequestration/storage

CFR Code of Federal Regulations

CHP combined heat and power

carbon dioxide

CO2e carbon dioxide equivalent

CPP Clean Power Plan

CSAPR Cross-State Air Pollution Rule

DOE Department of Energy

DOI Department of the Interior

DOT Department of Transportation

EGU electric generating unit

EIA Energy Information Administration

EJ environmental justice

E.O. Executive Order

EOR enhanced oil recovery

EPA Environmental Protection Agency

FEED front-end engineering and design

FGD flue gas desulfurization

FR Federal Register

FrEDI Framework for Evaluating Damages and Impacts

GHG greenhouse gas

GHGRP Greenhouse Gas Reporting Program

GW gigawatt

HHV higher heating value

HRSG heat recovery steam generator

IBR incorporate by reference

ICR information collection request

IGCC integrated gasification combined cycle

IIJA Infrastructure Investment and Jobs Act

IPCC Intergovernmental Panel on Climate Change

IRC Internal Revenue Code

IRP integrated resource plan

kg kilogram

kWh kilowatt-hour

LCOE levelized cost of electricity

LHV lower heating value

LNG liquefied natural gas

MMBtu/hr million British thermal units per hour

MMst million short tons

MMT CO

e million metric tons of carbon dioxide equivalent

MW megawatt

MWh megawatt-hour

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NCA4 2017-2018 Fourth National Climate Assessment

NETL National Energy Technology Laboratory

NGCC natural gas combined cycle

nitrogen oxides

NREL National Renewable Energy Laboratory

NSPS new source performance standards

NSR New Source Review

OMB Office of Management and Budget

PM particulate matter

PSD Prevention of Significant Deterioration

PUC public utilities commission

RIA regulatory impact analysis

RPS renewable portfolio standard

RTO Regional Transmission Organization

SCR selective catalytic reduction

SIP State Implementation Plan

U.S. United States

U.S.C. United States Code

Organization of this document.

The information in this preamble is organized as follows:

I. Executive Summary

A. Climate Change and the Power Sector

B. Overview of the Proposals

C. Recent Developments in Emissions Controls and the Electric Power Sector

D. How the EPA Considered Environmental Justice in the Development of These Proposals

II. General Information

A. Action Applicability

B. Where to Get a Copy of This Document and Other Related Information

C. Organization and Approach for These Proposed Rules

III. Climate Change and Its Impacts

IV. Recent Developments in Emissions Controls and the Electric Power Sector

A. Introduction

B. Background

C. CCS

D. Natural Gas Co-Firing

E. Hydrogen Co-Firing

F. Recent Changes in the Power Sector

G. GHG Emissions From Fossil Fuel-Fired EGUs

H. The Legislative, Market, and State Law Context

I. Projections of Power Sector Trends

V. Statutory Background and Regulatory History for CAA Section 111

A. Statutory Authority To Regulate GHGs From EGUs Under CAA Section 111

B. History of EPA Regulation of Greenhouse Gases From Electricity Generating Units Under CAA Section 111 and Caselaw

C. Detailed Discussion of CAA Section 111 Requirements

VI. Stakeholder Engagement

VII. Proposed Requirements for New and Reconstructed Stationary Combustion Turbine EGUs and Rationale for Proposed Requirements

A. Overview

B. Combustion Turbine Technology

C. Overview of Regulation of Stationary Combustion Turbines for GHGs

D. Eight-Year Review of NSPS

E. Applicability Requirements and Subcategorization

F. Determination of the Best System of Emission Reduction (BSER) for New and Reconstructed Stationary Combustion Turbines

G. Proposed Standards of Performance

H. Reconstructed Stationary Combustion Turbines

I. Modified Stationary Combustion Turbines

J. Startup, Shutdown, and Malfunction

K. Testing and Monitoring Requirements

L. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen

M. Recordkeeping and Reporting Requirements

N. Additional Solicitations of Comment and Proposed Requirements

O. Compliance Dates

VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-Fired Steam Generating Units

A. 2018 NSPS Proposal

B. Eight-Year Review of NSPS for Fossil Fuel-Fired Steam Generating Units

C. Projects Under Development

IX. Proposed ACE Rule Repeal

A. Summary of Selected Features of the ACE Rule

B. Developments Undermining ACE Rule's Projected Emission Reductions

C. Developments Showing That Other Technologies are the BSER for This Source Category

D. Insufficiently Precise Degree of Emission Limitation Achievable From Application of the BSER

E. ACE Rule's Preclusion of Emissions Trading or Averaging

X. Proposed Regulatory Approach for Existing Fossil Fuel-Fired Steam Generating Units

A. Overview

B. Applicability Requirements for Existing Fossil Fuel-Fired Steam Generating Units

C. Subcategorization of Fossil Fuel-Fired Steam Generating Units

D. Determination of BSER for Coal-Fired Steam Generating Units

E. Natural Gas-Fired and Oil-Fired Steam Generating Units

F. Summary

XI. Proposed Regulatory Approach for Emission Guidelines for Existing Fossil Fuel-fired Stationary Combustion Turbines

A. Overview

B. The Existing Stationary Combustion Turbine Fleet

C. BSER for Base Load Turbines Over 300 MW

D. Areas That the EPA is Seeking Comment on Related to Existing Combustion Turbines

E. BSER for Remaining Combustion Turbines

XII. State Plans for Proposed Emission Guidelines for Existing Fossil Fuel-Fired EGUs

A. Overview

B. Compliance Deadlines

C. Requirement for State Plans To Maintain Stringency of the EPA's BSER Determination

D. Establishing Standards of Performance

E. Compliance Flexibilities

F. State Plan Components and Submission

XIII. Implications for Other EPA Programs

A. Implications for New Source Review (NSR) Program

B. Implications for Title V Program

XIV. Impacts of Proposed Actions

A. Air Quality Impacts

B. Compliance Cost Impacts

C. Economic and Energy Impacts

D. Benefits

E. Environmental Justice Analytical Considerations and Stakeholder Outreach and Engagement

F. Grid Reliability Considerations

XV. Statutory and Executive Order Reviews

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

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act of 1995 (UMRA)

E. Executive Order 13132: Federalism

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

G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks Populations and Low-Income Populations

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

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51

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

Executive Summary

In 2009, the EPA concluded that GHG emissions endanger our nation's public health and welfare.

Since that time, the evidence of the harms posed by GHG emissions has only grown and Americans experience the destructive and worsening effects of climate change every day. Fossil fuel-fired EGUs are the nation's largest stationary source of GHG emissions, representing 25 percent of the United States' total GHG emissions in 2020. At the same time, a range of cost-effective technologies and approaches to reduce GHG emissions from these sources are available to the power sector, and multiple projects are in various stages of operation and development—including carbon capture and sequestration/storage (CCS) and co-firing with lower-GHG fuels. Congress has also acted to provide funding and other incentives to encourage the deployment of these technologies to

achieve reductions in GHG emissions from the power sector.

74 FR 66496 (December 15, 2009).

In this document, the EPA is proposing several actions under section 111 of the Clean Air Act (CAA) to reduce the significant quantity of GHG emissions from new and existing fossil fuel-fired EGUs by establishing new source performance standards (NSPS) and emission guidelines that are based on available and cost-effective technologies that directly reduce GHG emissions from these sources. Consistent with the statutory command of section 111, the proposed NSPS and emission guidelines reflect the application of the best system of emission reduction (BSER) that, taking into account costs, energy requirements, and other statutory factors, is adequately demonstrated.

Specifically, the EPA is proposing to update and establish more protective NSPS for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs that are based on highly efficient generating practices, hydrogen co-firing, and CCS. The EPA is also proposing to establish new emission guidelines for existing fossil fuel-fired steam generating EGUs that reflect the application of CCS and the availability of natural gas co-firing. The EPA is simultaneously proposing to repeal the Affordable Clean Energy (ACE) rule because the emission guidelines established in ACE do not reflect the BSER for steam generating EGUs and are inconsistent with section 111 of the CAA in other respects. To address GHG emissions from existing fossil fuel-fired stationary combustion turbines, the EPA is proposing emission guidelines for large and frequently used existing stationary combustion turbines. Further, the EPA is soliciting comment on how the Agency should approach its legal obligation to establish emission guidelines for the remaining existing fossil fuel-fired combustion turbines not covered by this proposal, including smaller frequently used, and less frequently used, combustion turbines.

Each of the NSPS and emission guidelines proposed here would ensure that EGUs reduce their GHG emissions in a manner that is cost-effective and improves the emissions performance of the sources, consistent with the applicable CAA requirements and caselaw. These proposed standards and emission guidelines, if finalized, would significantly decrease GHG emissions from fossil fuel-fired EGUs and the associated harms to human health and welfare. Further, the EPA has designed these proposed standards and emission guidelines in a way that is compatible with the nation's overall need for a reliable supply of affordable electricity.

A. Climate Change and the Power Sector

These proposals focus on reducing the emissions of GHGs from the power sector. The increasing concentrations of GHGs in the atmosphere are, and have been, warming the planet, resulting in serious and life-threatening environmental and human health impacts. The increased concentrations of GHGs in the atmosphere and the resulting warming have led to more frequent and more intense heat waves and extreme weather events, rising sea levels, and retreating snow and ice, all of which are occurring at a pace and scale that threatens human welfare.

The power sector in the United States (U.S.) is both a key contributor to the cause of climate change and a key component of the solution to the climate challenge. In 2020, the power sector was the largest stationary source of GHGs, emitting 25 percent of the overall domestic emissions.

These emissions are almost entirely the result of the combustion of fossil fuels in the EGUs that are the subjects of these proposals.

https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.

The power sector possesses many opportunities to contribute to solutions to the climate challenge. Particularly relevant to these proposals are several key technologies (co-firing of low-GHG fuels and CCS) that can allow steam generating EGUs and stationary combustion turbines (the focus of these proposals) to provide power while emitting significantly lower GHG emissions. Moreover, with the increased electrification of other GHG-emitting sectors of the economy, such as personal vehicles, heavy-duty trucks, and the heating and cooling of buildings, a power sector with lower GHG emissions can also help reduce pollution coming from other sectors of the economy.

B. Overview of the Proposals

As noted above, these actions include proposed BSER determinations and accompanying standards of performance for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbines, proposed repeal of the ACE Rule, proposed BSER determinations and emission guidelines for existing fossil fuel-fired steam generating units, proposed BSER determinations and emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines, and solicitation for comment on potential BSER options and emission guidelines for existing fossil fuel-fired stationary combustion turbines not otherwise covered by the proposal.

The EPA is taking these actions consistent with the process that CAA section 111 establishes. Under CAA section 111, once the EPA has identified a source category that emits dangerous air pollutants, it proceeds to regulate new sources and, for GHGs and certain other air pollutants, existing sources. The central requirement is that the EPA must determine the “best system of emission reduction . . . adequately demonstrated,” taking into account the cost of the reductions, non-air quality health and environmental impacts, and energy requirements. CAA section 111(a)(1). The EPA may determine that different sets of sources have different characteristics relevant for determining the BSER and may subcategorize sources accordingly.

Once it determines the BSER, the EPA must determine the “degree of emission limitation” achievable by application of the BSER. For new sources, the EPA determines the standard of performance with which the sources must comply, which is a standard for emissions that reflects the degree of emission limitation. For existing sources, the EPA includes the information it has developed concerning the BSER and associated degree of emission limitation into emission guidelines and directs the states to adopt State plans that contain standards of performance that are consistent with the emission guidelines.

Since the early 1970s, the EPA has promulgated regulations under section 111 for more than 60 source categories, which has established a robust regulatory history. During this period, the courts, primarily the U.S. Court of Appeals for the D.C. Circuit and the Supreme Court, have developed a body of caselaw interpreting section 111. As the Supreme Court has recognized, in these CAA section 111 actions, the EPA has determined the BSER to be “measures that improve the pollution performance of individual sources,” including add-on controls and clean fuels.

West Virginia

EPA,

142 S. Ct. 2587, 2614 (2022). For present purposes, several of a BSER's key features include that costs of controls must be reasonable, that the EPA may determine a control to be “adequately demonstrated” even if it is new and not yet in widespread commercial use, and, further, that the EPA may reasonably project the development of a control system at a future time and establish requirements that take effect at that time. The actions that the EPA is proposing are consistent with the requirements of CAA section 111 and its regulatory history and caselaw.

1. New and Reconstructed Fossil Fuel-Fired Combustion Turbines

For new and reconstructed fossil fuel-fired combustion turbines, the EPA is proposing to create three subcategories based on the function the combustion turbine serves: a low load (“peaking units”) subcategory that consists of combustion turbines with a capacity factor of less than 20 percent; an intermediate load subcategory for combustion turbines with a capacity factor that ranges between 20 percent and a source-specific upper bound that is based on the design efficiency of the combustion turbine; and a base load subcategory for combustion turbines that operate above the upper-bound threshold for intermediate load turbines. This subcategorization approach is similar to the current NSPS for these sources, which includes separate subcategories for base load and non-base load units; however, the EPA is now proposing to subdivide the non-base load subcategory into a low load subcategory and a separate intermediate load subcategory. This revised approach to subcategories is consistent with the fact that utilities and power plant operators are building new combustion turbines with plans to operate them at varying levels of capacity, in coordination with existing and expected energy sources. These patterns of operation are important for the type of controls that the EPA is proposing as the BSER for these turbines, in terms of the feasibility of, emissions reductions that would be achieved by, and cost-reasonableness of, those controls.

For the low load subcategory, the EPA is proposing that the BSER is the use of lower emitting fuels (

e.g.,

natural gas and distillate oil) with standards of performance ranging from 120 lb CO

/MMBtu to 160 lb CO

/MMBtu, depending on the type of fuel combusted.

For the intermediate load and base load subcategories, the EPA is proposing an approach in which the BSER has multiple components: (1) Highly efficient generation; and (2) depending on the subcategory, use of CCS or co-firing low-GHG hydrogen.

In the 2015 NSPS, the EPA referred to clean fuels as fuels with a consistent chemical composition (

i.e.,

uniform fuels) that result in a consistent emission rate of 69 kilograms per gigajoule (kg/GJ) (160 lb CO

/MMBtu). Fuels in this category include natural gas and distillate oil. In this rulemaking, the EPA refers to these fuels as both lower emitting fuels or uniform fuels.

These components of the BSER for the intermediate and base load subcategories form the basis of a standard of performance that applies in multiple phases. That is, affected facilities—which are facilities that commence construction or reconstruction after the date of publication in the

Federal Register

of this proposed rulemaking—must meet the first phase of the standard of performance, which is based exclusively on application of the first component of the BSER (highly efficient generation), by the date the rule is promulgated. Affected sources in the intermediate load and base load subcategories must also meet the second and in some cases third and more stringent phases of the standard of performance, which are based on the continued application of the first component of the BSER and the application of the second and in some cases third component of the BSER. For base load units, the EPA is proposing two pathways as potential BSER—(1) the use of CCS to achieve a 90 percent capture of GHG emissions by 2035 and (2) the co-firing of 30 percent (by volume) low-GHG hydrogen by 2032, and ramping up to 96 percent by volume low-GHG hydrogen by 2038. These two BSER pathways both offer significant opportunities to reduce GHG emissions but, may be available on slightly different timescales. Depending upon the phase in periods for both CCS and hydrogen, the CCS pathway could provide greater cumulative emission reductions than the low GHG hydrogen pathway. The EPA seeks comment specifically upon the percentages of hydrogen co-firing and CO

capture as well as the dates that meet the statutory BSER criteria for each pathway. The EPA solicits comment on the differences in emissions reductions in both scale and time that would result from the two standards and BSER pathways, including how to calculate the different amounts of emission reductions, how to compare them, and what conclusions to draw from those differences. The EPA also seeks comment on whether the Agency should finalize both pathways as separate subcategories with separate standards of performance, or whether it should finalize one pathway with the option of meeting the standard of performance using either system of emission reduction,

e.g.,

a single standard based on application of CCS with 90 percent capture, which could also be met by co-firing 96 percent (by volume) low-GHG hydrogen.

It should be noted that utilization of highly efficient generation is a logical complement to both CCS and co-firing of low-GHG hydrogen because, from both an economic and emissions perspective, that configuration will provide the greatest reductions at the lowest cost. This approach reflects the EPA's view that the BSER for the intermediate load and base load subcategories should reflect the deeper reductions in GHG emissions that can be achieved by implementing CCS and co-firing low-GHG hydrogen with the most efficient stationary combustion turbine configuration available. However, in proposing that compliance begins in 2032 (for co-firing with low-GHG hydrogen) and 2035 (for use of CCS), the EPA recognizes that building the infrastructure required to support wider use of CCS and qualified low-GHG hydrogen in the power sector will take place on a multi-year time scale.

More specifically, with respect to the first phase of the standards of performance, the EPA is proposing that the BSER for both the intermediate load and base load subcategories includes highly efficient generating technology (

i.e.,

the most efficient available turbines). For the intermediate load subcategory, the EPA is proposing that the BSER includes highly efficient simple cycle combustion turbine technology with an associated first phase standard of 1,150 lb CO

/MWh-gross. For the base load subcategory, the EPA is proposing that the BSER includes highly efficient combined cycle technology with an associated first phase standard of 770 lb CO

/MWh-gross for larger combustion turbine EGUs with a base load rating of 2,000 MMBtu/h or more. For smaller base load combustion turbines (with a base load rating of less than 2,000 MMBtu/h), the proposed associated standard would range from 770 to 900 lb CO

/MWh-gross depending on the specific base load rating of the combustion turbine. These standards would apply immediately upon the effective date of the final rule.

With respect to the second phase of the standards of performance, for the intermediate load subcategory, the EPA is proposing that the BSER includes co-firing 30 percent by volume low-GHG hydrogen (unless otherwise noted, all co-firing hydrogen percentages are on a volume basis) with an associated standard of 1,000 lb CO

/MWh-gross, compliance with which would be required starting in 2032. For the base load subcategory, to elicit comment on both pathways, the EPA is proposing to subcategorize further into base load units that are adopting the CCS pathway and base load units that are adopting the low-GHG hydrogen co-firing pathway. For the subcategory of base load units that are adopting the CCS pathway, the EPA is proposing that the BSER includes the use of CCS with 90 percent capture of CO

with an associated standard of 90 lb CO

/MWh-gross, compliance with which would be

required starting in 2035. For the subcategory of base load units that are adopting the low-GHG hydrogen co-firing pathway, the EPA is proposing that the BSER includes co-firing 30 percent (by volume) low-GHG hydrogen with an associated standard of 680 lb CO

/MWh-gross, compliance with which would be required starting in 2032, and co-firing 96 percent (by volume) low-GHG hydrogen by 2038, which corresponds to a standard of performance of 90 lb CO

/MWh-gross. In both cases, the second (and sometimes third) phase standard of performance would be applicable to all combustion turbines that were subject to the first phase standards of performance.

Existing and Modified Fossil Fuel-Fired Steam Generating Units and ACE Repeal

With respect to existing coal-fired steam generating units, the EPA is proposing to repeal and replace the existing ACE Rule emission guidelines. The EPA recognizes that, since it promulgated the ACE Rule, the costs of CCS have decreased due to technology advancements as well as new policies including the expansion of the Internal Revenue Code section 45Q tax credit for CCS in the Inflation Reduction Act (IRA); and the costs of natural gas co-firing have decreased as well, due in large part to a decrease in the difference between coal and natural gas prices. As a result, the EPA considered both CCS and natural gas co-firing as candidates for BSER for existing coal-fired steam EGUs.

Based on the latest information available to the Agency on cost, emission reductions, and other statutory criteria, the EPA is proposing that the BSER for existing coal-fired steam EGUs that expect to operate in the long-term is CCS with 90 percent capture of CO

. The EPA has determined that CCS satisfies the BSER criteria for these sources because it is adequately demonstrated, achieves significant reductions in GHG emissions, and is highly cost-effective.

Although the EPA considers CCS to be a broadly applicable BSER, the Agency also recognizes that CCS will be most cost-effective for existing steam EGUs that are in a position to recover the capital costs associated with CCS over a sufficiently long period of time. During the early engagement process (see Docket ID No. EPA-HQ-OAR-2022-0723-0024), industry stakeholders requested that the EPA “[p]rovide approaches that allow for the retirement of units as opposed to investments in new control technologies, which could prolong the lives of higher-emitting EGUs; this will achieve maximum and durable environmental benefits.” Industry stakeholders also suggested that the EPA recognize that some units may remain operational for a several-year period but will do so at limited capacity (in part to assure reliability), and then voluntarily cease operations entirely (see Docket ID No. EPA-HQ-OAR-2022-0723-0029).

In response to this industry stakeholder input and recognizing that the cost effectiveness of controls depends on the unit's expected operating time horizon, which dictates the amortization period for the capital costs of the controls, the EPA believes it is appropriate to establish subcategories of existing steam EGUs that are based on the operating horizon of the units. The EPA is proposing that for units that expect to operate in the long-term (

i.e.,

those that plan to operate past December 31, 2039), the BSER is the use of CCS with 90 percent capture of CO

with an associated degree of emission limitation of an 88.4 percent reduction in emission rate (lb CO

/MWh-gross basis). As explained in detail in this proposal, CCS with 90 percent capture of CO

is adequately demonstrated, cost reasonable, and achieves substantial emissions reductions from these units.

The EPA is proposing to define coal-fired steam generating units with medium-term operating horizons as those that (1) Operate after December 31, 2031, (2) have elected to commit to permanently cease operations before January 1, 2040, (3) elect to make that commitment federally enforceable and continuing by including it in the State plan, and (4) do not meet the definition of near-term operating horizon units. For these medium-term operating horizon units, the EPA is proposing that the BSER is co-firing 40 percent natural gas on a heat input basis with an associated degree of emission limitation of a 16 percent reduction in emission rate (lb CO

/MWh-gross basis). While this subcategory is based on a 10-year operating horizon (

i.e.,

January 1, 2040), the EPA is specifically soliciting comment on the potential for a different operating horizon between 8 and 10 years to define the threshold date between the definition of medium-term and long-term coal-fired steam generating units (

i.e.,

January 1, 2038 to January 1, 2040), given that the costs for CCS may be reasonable for units with amortization periods as short as 8 years. For units with operating horizons that are imminent-term,

i.e.,

those that (1) Have elected to commit to permanently cease operations before January 1, 2032, and (2) elect to make that commitment federally enforceable and continuing by including it in the State plan, the EPA is proposing that the BSER is routine methods of operation and maintenance with an associated degree of emission limitation of no increase in emission rate (lb CO

/MWh-gross basis). The EPA is proposing the same BSER determination for units in the near-term operating horizon subcategory,

i.e.,

units that (1) Have elected to commit to permanently cease operations by December 31, 2034, as well as to adopt an annual capacity factor limit of 20 percent, and (2) elect to make both of these conditions federally enforceable by including them in the State plan. The EPA is also soliciting comment on a potential BSER based on low levels of natural gas co-firing for units in these last two subcategories.

The EPA is not proposing to revise the NSPS for newly constructed or reconstructed fossil fuel-fired steam generating units, which it promulgated in 2015 (80 FR 64510; October 23, 2015). This is because the EPA does not anticipate that any such units will construct or reconstruct and is unaware of plans by any companies to construct or reconstruct a new coal-fired EGU. The EPA is proposing to revise the standards of performance that it promulgated in the same 2015 action for coal-fired steam generators that undertake a large modification (

i.e.,

a modification that increases its hourly emission rate by more than 10 percent) to mirror the emissions guidelines, discussed below, for existing coal-fired steam generators. This will ensure that all existing fossil fuel-fired steam generating sources are subject to the emission controls whether they modify or not.

The EPA is also proposing emission guidelines for existing natural gas-fired and oil-fired steam generating units. Recognizing that virtually all of these units have limited operation, the EPA is, in general, proposing that the BSER is routine methods of operation and maintenance with an associated degree of emission limitation of no increase in emission rate (lb CO

/MWh-gross).

3. Existing Fossil Fuel-Fired Stationary Combustion Turbines

The EPA is also proposing emission guidelines for large (

i.e.,

greater than 300 MW), frequently operated (

i.e.,

with a capacity factor of greater than 50 percent), existing fossil fuel-fired stationary combustion turbines. Because these existing combustion turbines are similar to new stationary combustion turbines, the EPA is proposing a BSER that is similar to the BSER for new base load combustion turbines. The EPA is

not proposing a first phase efficiency-based standard of performance; but the EPA is proposing that BSER for these units is based on either the use of CCS by 2035 or co-firing of 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing 96 percent low-GHG hydrogen by 2038.

For the emission guidelines for existing fossil fuel-fired steam generating units and large, frequently operated fossil fuel-fired combustion turbines, the EPA is also proposing State plan requirements, including submittal timelines for State plans and methodologies for determining presumptively approvable standards of performance consistent with BSER. This proposal also addresses how states can implement the remaining useful life and other factors (RULOF) provision of CAA section 111(d) and how states can conduct meaningful engagement with impacted stakeholders. Finally, the EPA is proposing to allow states to include trading or averaging in State plans so long as they demonstrate equivalent emissions reductions, and this proposal discusses considerations related to the appropriateness of including such compliance flexibilities.

Finally, the EPA is soliciting comment on a number of variations to the subcategories and BSER determinations, as well as the associated degrees of emission limitation and standards of performance, summarized above. The EPA is soliciting comment on the capacity and capacity factor threshold for inclusion in the subcategory of large, frequently operated turbines (

e.g.,

capacities between 100 MW and 300 MW for the capacity threshold and a lower capacity factor threshold (

e.g.,

40 percent). The EPA is also soliciting comment on BSER options and associated degrees of emission limitation for existing fossil fuel-fired stationary combustion turbines for which no BSER is being proposed (

i.e.,

fossil fuel-fired stationary combustion turbines that are not large, frequently operated turbines).

C. Recent Developments in Emissions Controls and the Electric Power Sector

Several recent developments concerning emissions controls and the state of the electric power sector are relevant for the EPA's determination of the BSER for existing coal-fired steam generating EGUs and natural gas-fired combustion turbines. These include developments that have led to significant reductions in the cost of CCS; expected increases in the availability and expected reductions in the cost of low-GHG hydrogen; and announced and planned retirements of coal-fired power plants.

In recent years, the cost of CCS has declined in part because of process improvements learned from earlier deployments of CCS and other advances. In addition, the IRA, enacted in 2022, extended and significantly increased the tax credit for CCS under Internal Revenue Code (IRC) section 45Q. As explained in detail in the BSER discussions later in this preamble, these changes support the EPA's proposed conclusion that CCS is the BSER for a number of subcategories in these proposals.

In addition, in both the Infrastructure Investment and Jobs Act (IIJA), enacted in 2021, and the IRA, Congress provided extensive support for the development of hydrogen produced through low-GHG methods. This support includes investment in infrastructure through the IIJA and the provision of tax credits in the IRA to incentivize the manufacture of hydrogen through low GHG-emitting methods. These changes also support the EPA's proposal that co-firing low-GHG hydrogen is BSER for certain subcategories of stationary combustion turbines.

The IIJA and IRA have also been part of the reason why many utilities and power generating companies have recently announced plans to change the mix of their generating assets. State legislation, technology advancements, market forces, consumer demand, and the fact that the existing fossil fuel-fired fleet is aging are also leading to, in most cases, decreased use of the fossil fuel-fired units that are the subjects of these proposals. Between 2010 and 2021, fossil fuel-fired generation declined from approximately 70 percent of total net generation to approximately 60 percent, with coal generation dropping from 46 percent to 23 percent of net generation during the period.

Many utilities and power generating companies have announced GHG reduction commitments as they further analyze and consider the incentives of the IRA. These utilities and companies have also announced their intention to permanently cease operating many of their remaining coal-fired EGUs. Some companies are planning to install combustion turbines with advanced technologies to limit GHG emissions, including CCS and hydrogen co-firing

(with some companies having announced plans to ultimately move to 100 percent hydrogen firing) and advanced energy storage technologies. As more renewables come online and as these technologies become more widely deployed, the utilization of natural gas-fired combustion turbine EGUs will be impacted. The EPA's post-IRA 2022 reference case modeling projects lower utilization relative to current levels of stationary combustion turbines.

See section VII.F.3.b of this preamble for discussion of CCS demonstrations and section VII.F.3.c for discussion of hydrogen co-firing demonstrations. Also see the

GHG Mitigation Measures for Steam Generating Units

TSD included in the rulemaking docket for this proposal.

The power sector has also been influenced by the actions of State governments to reduce GHG emissions. More than two-thirds of states have enacted policies to require utilities to increase the amount of electricity generated from sources that emit no GHGs. Other states have recently enacted significant legislation requiring the decarbonization of their utility fleets, using devices such as carbon markets, low-GHG emission standards, carbon capture and storage mandates, utility planning, or mandatory retirement schedules.

Additionally, Congress has recently enacted investments in GHG reductions. As noted earlier, Congress enacted IRC section 45Q by section 115 of the Energy Improvement and Extension Act of 2008, to provide a credit for the sequestration of CO

; IRC section 45Q was amended significantly by the Bipartisan Budget Act of 2018 and most recently by the IRA. The IIJA provided more than $65 billion for infrastructure investments and upgrades for transmission capacity, pipelines, and low-carbon fuels (including low-GHG hydrogen, as noted above). In addition, the Creating Helpful Incentives to Produce Semiconductors and Science Act (CHIPS Act) authorized billions more in funding for development of low- and non-GHG emitting energy technologies that will provide additional low-cost options for power companies to reduce overall GHG emissions.

https://www.congress.gov/bill/117th-congress/house-bill/4346.

Finally, the EPA has carefully considered the importance of maintaining resource adequacy and grid reliability in developing these proposals and is confident that these proposed NSPS and emission guidelines—with the extensive lead time and compliance flexibilities they provide—can be successfully implemented in a manner that preserves the ability of power companies and grid operators to maintain the reliability of the nation's electric power system. The EPA has evaluated the reliability implications of the proposal in the

Resource Adequacy Analysis

TSD; conducted dispatch modeling of the proposed NSPS and

proposed emission guidelines in a manner that takes into account resource adequacy needs; and consulted with the DOE and the Federal Energy Regulatory Commission (FERC) in the development of these proposals. Moreover, the EPA has included in these proposals the flexibility that power companies and grid operators need to plan for achieving feasible and necessary reductions of GHGs from these sources consistent with the EPA's statutory charge while ensuring grid reliability. Furthermore, the EPA is soliciting comment on localized impacts of these proposals on resource adequacy and reliability, and on opportunities to enhance reliable integration of the proposals into the power system.

D. How the EPA Considered Environmental Justice in the Development of These Proposals

Consistent with E.O. 12898, E.O. 13985 and the EPA's commitment to upholding environmental justice across its policies and programs, the EPA carefully considered the impacts of these proposals on communities with potential environmental justice concerns. As part of its pre-proposal outreach to stakeholders, the EPA engaged on multiple occasions with environmental justice organizations and representatives of communities that are affected by various forms of pollution from the power sector. The EPA took this feedback and analysis into account in its development of these proposals. The EPA's consideration of environmental justice in these proposals is briefly summarized here and discussed in further detail in sections XIV.E and XV.J of the preamble and section 6 of the RIA.

These proposals are focused on establishing NSPS and emission guidelines for GHGs, and these proposed actions will, in conjunction with other policies such as the IRA, play a significant role in reducing GHGs and move us a step closer to avoiding the worst impacts of climate change, which is already having a disproportionate impact on EJ communities. Beyond the GHG reductions, the EPA also has conducted a thorough evaluation of the impacts that these proposals would have on emissions of other health-harming air pollutants from EGUs, as well as how these changes in emissions would affect air quality and public health, particularly for historically overburdened populations including people of color, indigenous peoples, and people with low incomes.

The EPA's national-level analysis of emission reduction and public health impacts, which is documented in sections 3 and 4 of the RIA and summarized in greater detail in section XIV.A and XIV.D of this preamble, finds that these proposals would achieve nationwide reductions in EGU emissions of multiple health-harming air pollutants including nitrogen oxides (NO

), sulfur dioxide (SO

), and fine particulate matter (PM

2.5

). These reductions in health-harming pollution would result in significant public health benefits including avoided premature deaths, reductions in new asthma cases and incidences of asthma symptoms, reductions in hospital admissions and emergency department visits, and reductions in lost work and school days.

The EPA has also evaluated how the air quality impacts associated with these proposals would be distributed, with particular focus on potentially vulnerable populations. As discussed in section 6 of the RIA, these proposals are anticipated to lead to modest but widespread reductions in ambient levels of PM

2.5

for a large majority of the nation's population, as well as reductions in ambient PM

2.5

exposures that are similar in magnitude across all racial, ethnic, income and linguistic groups. Similarly, the EPA found that the proposed standards are anticipated to lead to modest but widespread reductions in ambient levels of ground-level ozone for the majority of the nation's population, and that in all but one of the years evaluated the proposed standards would lead to reductions in ambient ozone exposures across all demographic groups. Although these reductions in PM

2.5

and ozone exposures are small relative to baseline levels, and although disparities in PM

2.5

and ozone exposure would continue to persist following these proposals, the EPA's analysis indicates that the air quality benefits of these proposals would be broadly distributed.

Where authorized under section 111 of the Clean Air Act, the EPA has also incorporated provisions in these proposals to better address the needs and concerns of communities with environmental justice concerns. Specifically, the EPA's proposed emission guidelines for existing steam EGUs as well as existing fossil fuel-fired stationary combustion turbines would require states to undertake meaningful engagement with affected stakeholders, including communities that are most affected by and vulnerable to emissions from these EGUs. These meaningful engagement requirements are intended to ensure that the perspectives, priorities, and concerns of affected communities are included in the process of establishing and implementing standards of performance for existing EGUs, including decisions about compliance strategies and compliance flexibilities that may be included in a State plan.

In the Agency's pre-proposal outreach, some environmental justice organizations and community representatives raised strongly held concerns about the potential health, environmental, and safety impacts of CCS. The EPA believes that deployment of CCS can take place in a manner that is protective of public health, safety, and the environment, and should include early and meaningful engagement with affected communities and the public. As stated in the Council on Environmental Quality's (CEQ) February 2022 Carbon Capture, Utilization, and Sequestration Guidance, “the successful widespread deployment of responsible CCUS will require strong and effective permitting, efficient regulatory regimes, meaningful public engagement early in the review and deployment process, and measures to safeguard public health and the environment.” See 87 FR 8808 (February 16, 2022).

The EPA gave close consideration to these concerns as it developed its proposed determinations on the BSER for these proposed NSPS and emission guidelines, and addresses certain of the substantive issues that were raised in pre-proposal discussions in sections VII.F.3.b.iii(C) and X.D.1.a.iii of this preamble. As explained in these sections, the EPA is proposing to determine that CCS is the BSER for certain subcategories of new and existing EGUs based on its consideration of all of the statutory criteria for BSER, including emission reductions, cost, energy requirements, and non-air health and environmental considerations. In evaluating concerns raised by stakeholders in connection with CCS, the EPA is mindful that Federal agencies have “taken actions in the past decade to develop a robust CCUS regulatory framework to protect the environment and public health across multiple statutes.”

Carbon Capture, Utilization, and Sequestration Guidance, 87 FR 8808, 8809 (February 16, 2022),

https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.

This framework includes, among other things, the EPA regulation of geologic sequestration wells under the Underground Injection Control (UIC) program of the Safe Drinking Water Act; required reporting and public disclosure of geologic sequestration activity, as well as implementation of rigorous monitoring, reporting, and verification of geologic sequestration, under the

EPA's Greenhouse Gas Reporting Program; and safety regulations for CO

pipelines administered by the Pipeline and Hazardous Materials and Safety Administration (PHMSA). With respect to air emissions, some CCS projects may also require pre-construction permitting under the Clean Air Act's New Source Review (NSR) program and the adoption of additional emission limitations for non-GHG air pollutants based on applicable control technology requirements. The EPA invites public comment and feedback from stakeholders on all aspects of its proposed determination that CCS represents the BSER for certain new and existing fossil fuel-fired EGUs, including its evaluation of the various regulatory frameworks that apply to CCS.

CEQ's guidance, and the EPA's evaluation of BSER, recognizes that multiple Federal agencies have responsibility for regulating and permitting CCS projects, along with State and Tribal governments. The EPA is committed to working with Federal, State, and Tribal partners to ensure the responsible deployment of CCS, to protect communities from pollution, and to foster meaningful engagement with communities. This can be facilitated through the existing detailed regulatory framework for CCS projects and further supported through robust and meaningful public engagement early in the project development process. Furthermore, the EPA is requesting comment on what assistance states and pertinent stakeholders may need in conducting meaningful engagement with affected communities to ensure that there are adequate opportunities for public input on decisions to implement emissions control technology (including but not limited to CCS or low-GHG hydrogen).

II. General Information

A. Action Applicability

The source category that is the subject of these actions is comprised of the fossil fuel-fired electric utility generating units regulated under CAA section 111. The North American Industry Classification System (NAICS) codes for the source category are 221112 and 921150. The list of categories and NAICS codes is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that these proposed actions are likely to affect.

The proposed amendments to 40 CFR part 60, subpart TTTT, once promulgated, will be directly applicable to affected facilities that began construction after January 8, 2014, and affected facilities that began reconstruction or modification after June 18, 2014. The proposed NSPS, proposed to be codified in 40 CFR part 60, subpart TTTTa, once promulgated, will be directly applicable to affected facilities that begin construction or reconstruction after the date of publication of the proposed standards in the

Federal Register

. Federal, State, local, and Tribal government entities that own and/or operate EGUs subject to 40 CFR part 60, subparts TTTT or TTTTa would be affected by these proposed amendments and standards.

The proposed emission guidelines for GHG emissions from fossil fuel-fired EGUs proposed to be codified in 40 CFR part 60, subpart UUUUb, once promulgated, will be applicable to states in the development and submittal of State plans pursuant to CAA section 111(d). After the EPA promulgates a final emission guideline, each State that has one or more designated facilities must develop, adopt, and submit to the EPA a State plan under CAA section 111(d). The term “designated facility” means “any existing facility . . . which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility.” See 40 CFR 60.21a(b). If a State fails to submit a plan or the EPA determines that a State plan is not satisfactory, the EPA has the authority to establish a Federal CAA section 111(d) plan in such instances.

Under the Tribal Authority Rule adopted by the EPA, Tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to a State. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a State for purposes of developing a Tribal Implementation Plan (TIP) implementing an emission guideline. If a Tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for designated facilities that are located in areas of Indian country. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves a TIP applicable to those facilities.

B. Where To Get a Copy of This Document and Other Related Information

In addition to being available in the docket, an electronic copy of this action is available on the internet at

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

Following publication in the

Federal Register

, the EPA will post the

Federal Register

version of the proposals and key technical documents at this same website.

Memoranda showing the edits that would be necessary to incorporate the changes to 40 CFR part 60, subpart TTTT and UUUUa and new 40 CFR part 60, subparts TTTTa and UUUUb proposed in these actions are available in the docket (Docket ID No. EPA-HQ-OAR-2023-0072). Following signature by the EPA Administrator, the EPA also will post a copy of the documents at

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

C. Organization and Approach for These Proposed Rules

This rulemaking includes several proposed actions: (1) The EPA's proposed amendments to the Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (80 FR 64510; October 23, 2015) (2015 NSPS) and (2) proposed requirements for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. These actions also (3) propose to repeal the ACE Rule (84 FR 32523; July 8, 2019), (4) propose new emission guidelines for states in developing plans to reduce GHG emissions from existing fossil fuel-fired steam generating EGUs, which include both coal-fired and oil- and natural gas-fired steam generating EGUs, and (5) propose new emission guidelines for states in developing plans to reduce GHG emissions from existing fossil fuel-fired stationary combustion turbines. The EPA proposes that each of these actions function independently and are therefore severable. The EPA invites comment on the question of which portions of these proposed rules, if any, should be severable.

Section III of this preamble provides updated information on the impacts of climate change. In section IV, the EPA provides a summary of recent developments in emissions controls and the electric power sector. Section V presents a summary of the statutory background and regulatory history. In section VI, the EPA summarizes stakeholder outreach efforts. In section VII, the EPA describes the proposed BSERs, standards of performance, and associated requirements for new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. In section

VIII, the EPA presents proposed amendments to requirements for new, reconstructed, and modified fossil fuel-fired steam generating units. In section IX, the EPA provides a summary of the ACE Rule and proposes its repeal. In section X, the EPA presents the proposed BSERs, degree of emission limitation, and related requirements for the proposed emission guidelines for existing fossil fuel-fired steam generating EGUs. In section XI, the EPA presents the proposed BSERs, degree of emission limitation, and related requirements for the proposed emission guidelines for existing natural gas-fired combustion turbines. Section XII presents the requirements for State plan development. In section XIII, the EPA describes the implications for these proposals on other EPA programs and rules. Section XIV describes the impacts of these proposals. Finally, in section XV, the EPA provides the statutory and executive order reviews.

III. Climate Change and Its Impacts

Elevated concentrations of GHGs are and have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are transforming the climate at a pace and scale that threatens human health, society, and the natural environment. Human-induced GHGs, largely derived from our reliance on fossil fuels, are causing serious and life-threatening environmental and health impacts.

Extensive additional information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section, as well as in the technical and scientific information supporting them. One of those documents is the EPA's 2009 Endangerment and Cause or Contribute Findings for GHGs Under section 202(a) of the CAA (74 FR 66496; December 15, 2009).

In the 2009 Endangerment Findings, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—carbon dioxide (CO

), methane (CH

), nitrous oxide (N

O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF

)—“may reasonably be anticipated to endanger the public health and welfare of current and future generations” (74 FR 66523; December 15, 2009), and the science and observed changes have confirmed and strengthened the understanding and concerns regarding the climate risks considered in the Finding. The 2009 Endangerment Findings, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497; December 15, 2009). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. (74 FR 66525; December 15, 2009). The 2009 Endangerment Findings further explained that compared to a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525; December 15, 2009). Climate change is also expected to cause more intense hurricanes and more frequent and intense storms of other types and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders (74 FR 66525; December 15, 2009). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498; December 15, 2009).

In describing these 2009 Findings in these proposals, the EPA is neither reopening nor revisiting them.

The 2009 Endangerment Findings also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare

in the U.S. including changes in water supply and quality due to increased frequency of drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; predominantly negative consequences for biodiversity and the provisioning of ecosystem goods and services; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530; December 15, 2009).

The CAA states in section 302(h) that “[a]ll language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.” 42 U.S.C. 7602(h).

In 2016, the Administrator similarly issued Endangerment and Cause or Contribute Findings for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA (81 FR 54422; August 15, 2016).

In the 2016 Endangerment Findings, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Findings compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A) and also found that the science assessments released between the 2009 and the 2016 Findings, “strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations.” 81 FR 54424 (August 15, 2016).

In describing these 2016 Findings in these proposals, the EPA is neither reopening nor revisiting them.

Since the 2016 Endangerment Findings, the climate has continued to change, with new records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Moreover, heavy precipitation events have increased in the Eastern U.S. while agricultural and ecological drought has increased in the Western U.S. along with more intense and larger wildfires.

These and other trends are examples of the risks discussed in the 2009 and 2016 Endangerment Findings that have already been experienced. Additionally, major scientific assessments continue to demonstrate advances in our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both

globally and in the U.S. These assessments include:

See later in this section for specific examples. An additional resource for indicators can be found at

https://www.epa.gov/climate-indicators.

• U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health Assessment

and 2017-2018 Fourth National Climate Assessment (NCA4).

12 13

USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp.

USGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi: 10.7930/J0J964J6.

USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.

• Intergovernmental Panel on Climate Change (IPCC) 2018 Global Warming of 1.5 °C,

2019 Climate Change and Land,

and the 2019 Ocean and Cryosphere in a Changing Climate

assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6).

17 18

IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Portner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)].

IPCC, 2019: Climate Change and Land: an IPCC special report on climate change, desertification, land degradation, sustainable land management, food security, and greenhouse gas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. Masson-Delmotte, H.-O. Portner, D.C. Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K. Kissick, M. Belkacemi, J. Malley (eds.)].

IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere in a Changing Climate [H.-O. Pörtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A. Alegrı´a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer (eds.)].

IPCC, 2021: Summary for Policymakers. In: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc

i, R. Yu and B. Zhou (eds.)]. Cambridge University Press.

IPCC, 2022: Summary for Policymakers [H.-O. Pörtner, D.C. Roberts, E.S. Poloczanska, K. Mintenbeck, M. Tignor, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem (eds.)]. In: Climate Change 2022: Impacts, Adaptation and Vulnerability. Contribution of Working Group II to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [H.-O. Pörtner, D.C. Roberts, M. Tignor, E.S. Poloczanska, K. Mintenbeck, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem, B. Rama (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, New York, USA, pp. 3-33, doi:10.1017/9781009325844.001.

• The National Academy of Sciences (NAS) 2016 Attribution of Extreme Weather Events in the Context of Climate Change,

2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide,

and 2019 Climate Change and Ecosystems

assessments.

National Academies of Sciences, Engineering, and Medicine. 2016. Attribution of Extreme Weather Events in the Context of Climate Change. Washington, DC: The National Academies Press.

https://dio.org/10.17226/21852.

National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press.

https://doi.org/10.17226/24651.

National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press.

https://doi.org/10.17226/25504.

• National Oceanic and Atmospheric Administration's (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society,

most recently in August of 2022.

Blunden, J. and T. Boyer, Eds., 2022: “State of the Climate in 2021.” Bull. Amer. Meteor. Soc., 103 (8), Si-S465,

https://doi.org/10.1175/2022BAMSStateoftheClimate.1.

• EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021).

EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.

The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in the atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily as a result of both historic and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments. For example, the annual global average atmospheric concentrations of one of these GHGs, CO

, measured at Mauna Loa in Hawaii and at other sites around the world reached 415 parts per million (ppm) in 2020 (nearly 50 percent higher than pre-industrial levels)

and has continued to rise at a rapid rate. Global average temperature has increased by about 1.1 degrees Celsius (°C) (2.0 degrees Fahrenheit (°F)) in the 2011-2020 decade relative to 1850-1900.

The years 2015-2021 were the warmest 7 years in the 1880-2020 record according to six different global surface temperature datasets.

The IPCC determined with medium confidence that this past decade was warmer than any multi-century period in at least the past 100,000 years.

Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate over the 1971 to 2006 period and three times the rate of the 1901 to 2018 period.

The rate of sea level rise during the 20th Century was higher than in any other century in at least the last 2,800 years.

Higher CO

concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 2 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons.

Arctic sea ice extent continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1,000 years.

Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts

in many regions.

Blunden, J. and T. Boyer, Eds., 2022: “State of the Climate in 2021.” Bull. Amer. Meteor. Soc., 103 (8), Si-S465,

https://doi.org/10.1175/2022BAMSStateoftheClimate.1.

IPCC, 2021.

Blunden, J. and T. Boyer, Eds., 2022.

IPCC, 2021.

These are drought measures based on soil moisture.

IPCC, 2021.

The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The present-day CO

concentration of 415 ppm is already higher than at any time in the last 2 million years.

If concentrations exceed 450 ppm, they would likely be higher

than at any time in the past 23 million years:

At the current rate of increase of more than 2 ppm per year, this will occur in about 15 years. While buildup of GHGs is not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO

concentrations were this high) Greenland was not yet completely covered by ice and still supported forests, while 23 million years ago (the last time concentrations were above 450 ppm) the West Antarctic ice sheet was not yet developed, indicating the possibility that high GHG concentrations could lead to a world that looks very different from today and from the conditions in which human civilization has developed.

IPCC, 2021.

IPCC, 2013.

Gulev, S.K., P.W. Thorne, J. Ahn, F.J. Dentener, C.M. Domingues, S. Gerland, D. Gong, D.S. Kaufman, H.C. Nnamchi, J. Quaas, J.A. Rivera, S. Sathyendranath, S.L. Smith, B. Trewin, K. von Schuckmann, and R.S. Vose, 2021: Changing State of the Climate System. In Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Péan, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi, R. Yu, and B. Zhou (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, New York, USA, pp. 287-422, doi:10.1017/9781009157896.004.

If the Greenland and Antarctic ice sheets were to melt substantially, for example, sea levels would rise dramatically, with potentially severe consequences for coastal cities and infrastructure. The IPCC estimated that during the next 2,000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5 °C (2.7 °F), from 7 to 20 feet if limited to 2 °C (3.6 °F), and by 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels.

For context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise. Moreover, the CO

being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years,

putting many marine species—particularly calcifying species—at risk.

IPCC, 2021.

IPCC, 2018.

IPCC, 2021.

The NCA4 found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years.

Coral reefs will be at risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional warming from today (2 °C or 3.6 °F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost.

The IPCC similarly found that climate change has caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, and coastal and open ocean marine ecosystems.

USGCRP, 2018.

IPCC, 2018.

IPCC, 2022.

Every additional increment of temperature comes with consequences. For example, the half degree of warming from 1.5 to 2 °C (0.9 °F of warming from 2.7 °F to 3.6 °F) above preindustrial temperatures is projected on a global scale to expose 420 million more people to frequent extreme heatwaves and 62 million more people to frequent exceptional heatwaves (where heatwaves are defined based on a heat wave magnitude index which takes into account duration and intensity—using this index, the 2003 French heat wave that led to almost 15,000 deaths would be classified as an “extreme heatwave” and the 2010 Russian heatwave which led to thousands of deaths and extensive wildfires would be classified as “exceptional”). This half degree temperature increase has been projected to lead to an increase in the frequency of sea-ice-free Arctic summers from once in a hundred years to once in a decade. It could lead to 4 inches of additional sea level rise by the end of the century, exposing an additional 10 million people to risks of inundation, as well as increasing the probability of triggering instabilities in either the Greenland or Antarctic ice sheets. Between half a million and a million additional square miles of permafrost is projected to thaw over several centuries. Risks to food security is projected to increase from medium to high for several lower income regions in the Sahel, southern Africa, the Mediterranean, central Europe, and the Amazon. In addition to food security issues, this temperature increase is projected to have implications for human health in terms of increasing ozone concentrations, heatwaves, and vector-borne diseases (for example, expanding the range of the mosquitoes which carry dengue fever, chikungunya, yellow fever, and the Zika virus or the ticks which carry lyme, babesiosis, or Rocky Mountain Spotted Fever).

Moreover, every additional increment in warming leads to larger changes in extremes, including the potential for events unprecedented in the observational record. Every additional degree is projected to intensify extreme precipitation events by about 7 percent. The peak winds of the most intense tropical cyclones (hurricanes) are projected to increase with warming. In addition to a higher intensity, the IPCC found that precipitation and frequency of rapid intensification of these storms has already increased, while the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging.

IPCC, 2018.

IPCC, 2021.

The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in the Western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually.

The National Interagency Fire Center has documented U.S. wildfires since 1983, and the 10 years with the largest acreage burned have all occurred since 2004.

Wildfire smoke degrades air quality increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities, sometimes thousands of miles from the location of the fire. Meanwhile, sea level rise has amplified coastal flooding and erosion impacts, leading to salt water intrusion into coastal aquifers and groundwater, flooding streets, increasing storm surge damages, and threatening coastal property and ecosystems, requiring costly adaptive measures such as installation of pump stations, beach nourishment, property elevation, and shoreline armoring. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 under some scenarios. Increased frequency and duration of drought will reduce agricultural productivity in some regions, accelerate depletion of water supplies for irrigation, and expand the distribution and incidence of pests and diseases for crops and livestock. The NCA4 also recognized that climate change can increase risks to national

security, both through direct impacts on military infrastructure, but also by affecting factors such as food and water availability that can exacerbate conflict outside U.S. borders. Droughts, floods, storm surges, wildfires, and other extreme events stress nations and people through loss of life, displacement of populations, and impacts on livelihoods.

USGCRP, 2018.

NIFC (National Interagency Fire Center). 2022. Total wildland fires and acres (1983-2020). Accessed November 2022.

https://www.nifc.gov/sites/default/files/document-media/TotalFires.pdf.

USGCRP, 2018.

Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of CO

stimulate plant growth (which can be positive in the case of beneficial species, but negative in terms of weeds and invasive species, and can also lead to a reduction in plant micronutrients)

and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone.

The tropospheric ozone produced by the reaction of methane in the atmosphere has harmful effects for human health and plant growth in addition to its climate effects.

Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Perez de Leon, A. Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, and Distribution. The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. U.S. Global Change Research Program, Washington, DC, 189-216,

https://dx.doi.org/10.7930/J0ZP4417.

WMO (World Meteorological Organization), Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project—Report No. 58, 588 pp., Geneva, Switzerland, 2018.

Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air Quality. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018. CH13.

Ongoing EPA modeling efforts can shed further light on the distribution of climate change damages expected to occur within the U.S. Based on methods from over 30 peer-reviewed climate change impact studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI) model has developed estimates of the relationship between future temperature changes and physical and economic climate-driven damages occurring in specific U.S. regions across 20 impact categories, which span a large number of sectors of the U.S. economy.

Recent applications of FrEDI have advanced the collective understanding about how future climate change impacts in these 20 sectors are expected to be substantial and distributed unevenly across U.S. regions.

Using this framework, the EPA estimates that under a global emission scenario with no additional mitigation, relative to a world with no additional warming since the baseline period (1986-2005), damages accruing to these 20 sectors in the contiguous U.S. occur mainly through increased deaths due to increasing temperatures, as well as climate-driven changes in air quality, transportation impacts due to coastal flooding resulting from sea level rise, increased mortality from wildfire emission exposure and response costs for fire suppression, and reduced labor hours worked in outdoor settings and buildings without air conditioning. The relative damages from long-term climate driven changes in these sectors are also projected vary from region to region: for example, the Southeast is projected to see some of the largest damages from sea level rise, the West Coast will see higher damages from wildfire smoke than other parts of the country, and the Northern Plains states are projected to see a higher proportion of damages to rail and road infrastructure. While the FrEDI framework currently quantifies damages for 20 sectors within the U.S., it is important to note that it is still a preliminary and partial assessment of climate impacts relevant to U.S. interests in a number of ways. For example, FrEDI does not reflect increased damages that occur due to interactions between different sectors impacted by climate change or all the ways in which physical impacts of climate change occuring abroad have spillover effects in different regions of the U.S. See the FrEDI Technical Documentation

for more details.

EPA. (2021). Technical Documentation on the Framework for Evaluating Damages and Impacts (FrEDI). U.S. Environmental Protection Agency, EPA 430-R-21-004, available at

https://www.epa.gov/cira/fredi.

Documentation has been subject to both a public review comment period and an independent expert peer review, following EPA peer-review guidelines.

(1) Sarofim, M.C., Martinich, J., Neumann, J.E.,

et al.

(2021).

A temperature binning approach for multi-sector climate impact analysis.

Climatic Change 165.

https://doi.org/10.1007/s10584-021-03048-6,

(2)

Supplementary Material for the Regulatory Impact Analysis for the Supplemental Proposed Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,”

Docket ID No. EPA-HQ-OAR-2021-0317, September 2022, (3)

The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.

Published by the U.S. Department of State and the U.S. Executive Office of the President, Washington DC. November 2021, (4)

Climate Risk Exposure: An Assessment of the Federal Government's Financial Risks to Climate Change,

White Paper, Office of Management and Budget, April 2022.

EPA. (2021). Technical Documentation on the Framework for Evaluating Damages and Impacts (FrEDI). U.S. Environmental Protection Agency, EPA 430-R-21-004, available at

https://www.epa.gov/cira/fredi.

These scientific assessments, EPA analyses, and documented observed changes in the climate of the planet and of the U.S. present clear support regarding the current and future dangers of climate change and the importance of GHG emissions mitigation.

IV. Recent Developments in Emissions Controls and the Electric Power Sector

A. Introduction

In this section, we discuss background information about the electric power sector and then discuss several recent developments that are relevant for many of the controls that the EPA is proposing to determine qualify as the BSER for the fossil fuel-fired power plants that are the subject of this proposed rulemaking. After giving some general background, we first discuss CCS and explain that its cost has fallen significantly. Lower CCS costs are central for the EPA's proposals that CCS is the BSER for certain existing coal-fired EGUs and certain existing and new natural gas-fired combustion turbines. Second, we discuss natural gas co-firing for coal-fired EGUs and explain recent reductions in cost for this approach as well as its widespread availability and current and potential deployment within this source category. Third, we discuss hydrogen produced through low-emitting manufacturing, the availability of which is expected to increase significantly and the cost of which is expected to decline significantly in the near future. This increase in availability and decrease in cost is central for the EPA's proposal that low-GHG hydrogen is the BSER for certain existing and new natural gas-fired combustion turbines. Finally, we discuss key developments in the electric power sector that underly the expected operational methods for existing coal-fired EGUs and new and existing natural gas-fired combustion turbines. These key developments, in turn, are relevant for the regulatory design.

B. Background

1. Electric Power Sector

Electricity in the U.S. is generated by a range of technologies, and while the sector is rapidly evolving, the stationary combustion turbines and steam generating EGUs that are the subject of these proposed regulations still provide more than half of the electricity generated in the U.S. These EGUs fill many roles that are important to maintaining a reliable supply of electricity. For example, certain EGUs generate base load power, which is the portion of electricity loads that are continually present and typically

operate throughout all hours of the year. Other EGUs provide complementary generation to balance variable supply and demand resources. “Peaking units” provide capacity during hours of the highest daily, weekly, or seasonal net demand. Some EGUs also play important roles ensuring the reliability of the electric grid, including facilitating the regulation of frequency and voltage, providing “black start” capability in the event the grid must be repowered after a widespread outage, and providing reserve generating capacity

in the event of unexpected changes in the availability of other generators.

Generation and capacity are commonly reported statistics with key distinctions. Generation is the production of electricity and is a measure of an EGU's

actual

output while capacity is a measure of the maximum

potential

production of an EGU under certain conditions. There are several methods to calculate an EGU's capacity, which are suited for different applications of the statistic. Capacity is typically measured in megawatts (MW) for individual units or gigawatts (1 GW = 1,000 MW) for multiple EGUs. Generation is often measured in kilowatt-hours (kWh), megawatt-hours (MWh), or gigawatt-hours (1 GWh = 1 million kWh).

In general, the EGUs with the lowest operating costs are dispatched first, and, as a result, an inefficient EGU with high fuel costs will typically only operate if other lower-cost plants are unavailable or insufficient to meet demand. Units are also unavailable during both routine and unanticipated outages, which typically become more frequent as power plants age. These factors result in the mix of available generating capacity types (

e.g.,

the share of capacity of each type of generating source) being substantially different than the mix of the share of total electricity produced by each type of generating source in a given season or year.

Generated electricity must be transmitted over networks

of high voltage lines to substations where power is stepped down to a lower voltage for local distribution. Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled by regional organizations to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator;

in others, individual utilities

coordinate the operations of their generation and transmission to balance the system across their respective service territories.

The three network interconnections are the Western Interconnection, comprising the western parts of both the U.S. and Canada (approximately the area to the west of the Rocky Mountains), the Eastern Interconnection, comprising the eastern parts of both the U.S. and Canada (except those parts of Eastern Canada that are in the Quebec Interconnection), and the Texas Interconnection (which encompasses the portion of the Texas electricity system commonly known as the Electric Reliability Council of Texas (ERCOT)). See map of all NERC interconnections at

https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf.

For example, PJM Interconnection, LLC, New York Independent System Operator (NYISO), Midwest Independent System Operator (MISO), California Independent System Operator (CAISO), etc.

For example, Los Angeles Department of Power and Water, Florida Power and Light, etc.

2. Types of EGUs

In 2021, approximately 61 percent of net electricity was generated from the combustion of fossil fuels with natural gas providing 38 percent, coal providing 22 percent, and petroleum products such as fuel oil providing an additional 1 percent.

Fossil fuel-fired EGUs include the steam generating units and stationary combustion turbines that are the subject of these proposed regulations.

U.S. Energy Information Administration (EIA).

Electric Power Monthly, Table 1.1 and Form EIA-860M,

July 2022.

https://www.eia.gov/electricity/data/php.

There are two forms of fossil fuel-fired electric utility steam generating units: utility boilers and those that use gasification technology (

i.e.,

integrated gasification combined cycle (IGCC) units). While coal is the most common fuel for fossil fuel-fired utility boilers, natural gas can also be used as a fuel in these EGUs and many existing coal- and oil-fired utility boilers have repowered as natural gas-fired units. An IGCC unit gasifies fuel—typically coal or petroleum coke—to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H

), which can be combusted in a combined cycle system to generate power. The heat created by these technologies produces high-pressure steam that is released to rotate turbines, which, in turn, spin an electric generator.

Stationary combustion turbine EGUs (most commonly natural gas-fired) use one of two configurations: combined cycle or simple cycle combustion turbines. Combined cycle units have two generating components (

i.e.,

two cycles) operating from a single source of heat. Combined cycle units first generate power from a combustion turbine (

i.e.,

the combustion cycle) directly from the heat of burning natural gas or other fuel. The second cycle reuses the waste heat from the combustion turbine engine, which is routed to a heat recovery steam generator (HRSG) that generates steam, which is then used to produce additional power using a steam turbine (

i.e.,

the steam cycle). Combining these generation cycles increases the overall efficiency of the system. Combined cycle units that fire mostly natural gas are commonly referred to as natural gas combined cycle (NGCC) units, and, with greater efficiency, are utilized at higher capacity factors to provide base load or intermediate power. An EGU's capacity factor indicates a power plant's electricity output as a percentage of its total generation capacity. Simple cycle combustion turbines only use a combustion turbine to produce electricity (

i.e.,

there is no heat recovery or steam cycle). These less-efficient combustion turbines are generally utilized at non-base load capacity factors and contribute to reliable operations of the grid during periods of peak demand or provide flexibility to support increased generation from variable energy sources.

Non-dispatchable renewable energy (electrical output cannot be used at any given time to meet fluctuating demand) is both variable and intermittent and is often referred to as intermittent renewable energy. The variability aspect results from predictable changes in electric generation (

e.g.,

solar not generating electricity at night) that often occur on longer time periods. The intermittent aspect of renewable energy results from inconsistent generation due to unpredictable external factors outside the control of the owner/operator (

e.g.,

imperfect local weather forecasts) that often occur on shorter time periods. Since renewable energy fluctuates over multiple time periods, grid operators are required to adjust forecast and real time operating procedures. As more renewable energy is added to the electric grid and generation forecasts improve, the intermittency of renewable energy is reduced.

Other generating sources produce electricity by harnessing kinetic energy from flowing water, wind, or tides, thermal energy from geothermal wells, or solar energy primarily through photovoltaic solar arrays. Spurred by a combination of declining costs, consumer preferences, and government policies, the capacity of these renewable technologies is growing, and when considered with existing nuclear energy, accounted for nearly 41 percent of the overall net electricity supply in 2022. Many projections show this share growing over time. For example, the EPA's Power Sector Modeling Platform v6 Using the Integrated Planning Model post-IRA 2022 reference case (

i.e.,

the EPA's projections of the power sector, which includes representation of the IRA absent further regulation) shows zero-emitting sources reaching 76 percent of electricity generation by 2040. (See section IV.F of this preamble and the accompanying RIA for additional discussion of projections for the power sector). These projections are consistent with power company announcements. For example, as the Edison Electric Institute (EEI) stated in pre-proposal public comments

submitted to the regulatory docket: “Fifty EEI members have announced forward-looking carbon reduction goals, two-thirds of which include a net-zero by 2050 or earlier equivalent goal, and members are routinely increasing the ambition or speed of their goals or altogether transforming them into net-zero goals . . . . EEI's member companies see a clear path to continued emissions reductions over the next decade using current technologies, including nuclear power, natural gas-based generation, energy demand efficiency, energy storage, and deployment of new renewable energy—especially wind and solar—as older coal-based and less-efficient natural gas-based generating units retire.”

Edison Electric Institute (EEI). (November 18, 2022).

Clean Air Act Section 111 Standards and the Power Sector: Considerations and Options for Setting Standards and Providing Compliance Flexibility to Units and States.

Pg. 5. Public comments submitted to the EPA's pre-proposal rulemaking, Docket ID No. EPA-HQ-OAR-2022-0723.

C. CCS

One of the key GHG reduction technologies upon which BSER determinations are founded in this proposal is CCS—a technology that can capture and permanently store CO

from EGUs. CCS has three major components: CO

capture, transportation, and sequestration/storage. Generally, the capture processes most applicable to combustion turbines and utility boilers remove CO

from the exhaust gas after combustion. The exhaust gases from most combustion processes are at atmospheric pressure with relatively low concentrations of CO

. Most post-combustion capture systems utilize liquid solvents (most commonly amine-based) in a scrubber column to absorb the CO

from the flue gas.

The CO

-rich solvent is then regenerated by heating the solvent to release the captured CO

. The high purity CO

is then compressed and transported, generally through pipelines, to a site for geologic sequestration (

i.e.,

the long-term containment of CO

in subsurface geologic formations).

Process improvements learned from earlier deployments of CCS, the availability of better solvents, and other advances have resulted in a decrease in the cost of CCS in recent years. The cost of CO

capture, excluding any tax credits, from coal-fired power generation is projected to fall by 50 percent by 2025 compared to 2010.

In addition, new policies such as the IRA, enacted in 2022, support the deployment of CCS technology and will further reduce the cost of implementing CCS by extending and increasing the tax credit for CCS under Internal Revenue Code section 45Q.

Post-combustion CO

capture is most common, but as discussed later in this preamble, there are also pre-combustion CO

capture options available and applicable to the power sector.

40 CFR 261.4(h).

Technology Readiness and Costs of CCS (2021). Global CCS Institute.

https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.

There are several examples of the application of CCS at EGUs, some of which are noted here with further detail provided in section VII.F.3.b.iii(A) of this preamble. These include SaskPower's Boundary Dam Unit 3, a 110-MW lignite-fired unit in Saskatchewan, Canada, which has achieved CO

capture rates of 90 percent using an amine-based post-combustion capture system retrofitted to the existing steam generating unit.

Amine-based carbon capture has also been demonstrated at AES's Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants.

Giannaris, S.,

et al.

Proceedings of the 15th International Conference on Greenhouse Gas Control Technologies (March 15-18, 2021).

SaskPower's Boundary Dam Unit 3 Carbon Capture Facility-The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.

Dooley, J.J., et al. (2009). “An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009.” U.S. DOE, Pacific Northwest National Laboratory, under Contract DE-AC05-76RL01830.

CCS has also been successfully applied to an existing combined cycle combustion turbine EGU at the Bellingham Energy Center in south central Massachusetts, and other projects are in different stages of deployment. The 40-MW slipstream capture facility at the Bellingham Energy Center operated from 1991 to 2005 and captured 85 to 95 percent of the CO

in the slipstream.

In Scotland, the proposed 900-MW Peterhead Power Station combined cycle EGU with CCS is in the planning stages of deployment and will have the potential to capture 90 percent of its CO

emissions.

Moreover, an 1,800-MW combined cycle EGU that will be constructed in West Virginia and will utilize CCS has been announced. The project is planned to begin operation later this decade, and its economic feasibility was partially credited to the expanded IRC section 45Q tax credit for sequestered CO

provided through the IRA.

U.S. Department of Energy (DOE). Carbon Capture Opportunities for Natural Gas Fired Power Systems.

https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.

Buli, N. (2021, May 10). SSE, Equinor plan new gas power plant with carbon capture in Scotland.

Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.

Competitive Power Ventures (2022).

Multi-Billion Dollar Combined Cycle Natural Gas Power Station with Carbon Capture Announced in West Virginia.

Press Release. September 16, 2022.

https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.

In developing these proposals, the EPA reviewed the current state of CCS technology and costs, including the use of CCS with both steam generating units and combustion turbines. This review is reflected in the BSER discussions later in this preamble and is further detailed in the accompanying RIA and technical support documents titled,

GHG Mitigation Measures for Steam Generating Units

and

GHG Mitigation Measures—Carbon Capture and Storage for Combustion Turbines.

The three documents are included in the rulemaking docket.

D. Natural Gas Co-Firing

For a coal-fired steam generating unit, the substitution of natural gas for some of the coal so that the unit fires a combination of coal and natural gas is known as “natural gas co-firing.” Most existing coal-fired steam generating units can be modified to co-fire natural gas in any desired proportion with coal. Generally, the modification of existing boilers to enable or increase natural gas firing typically involves the installation of new gas burners and related boiler modifications as well as the construction of natural gas supply pipelines. In recent years, the cost of natural gas co-firing has declined because the expected difference between coal and gas prices has decreased to about $1/MMBtu and recent analyses support lower capital costs for modifying existing boilers to co-fire with natural gas, as discussed in section X.D.2 of this preamble.

In developing these proposals, the EPA reviewed in detail the current state of natural gas co-firing technology and costs. This review is reflected in the BSER discussions later in this preamble and is further detailed in the accompanying RIA and

GHG Mitigation Measures for Steam Generating Units

TSD. Both documents are included in the rulemaking docket.

E. Hydrogen Co-Firing

Industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades, and recently, utility combustion turbines in the power sector have begun to co-fire hydrogen as

a fuel to generate electricity. Hydrogen contains no carbon, and when combusted in a turbine, produces zero direct CO

emissions. However, as discussed in section IV.F.3 of this preamble, the manufacture of hydrogen, depending on the method of production, can generate GHG emissions. As noted previously, there has been a growing interest in the use of hydrogen as a fuel for combustion turbines to generate electricity. Many models of new utility combustion turbines have demonstrated the ability to co-fire up to 30 percent hydrogen and developers are working toward models that will be ready to combust 100 percent hydrogen by 2030. Furthermore, several utilities are co-firing hydrogen in test burns; and some have announced plans to move to combusting 100 percent hydrogen in the 2035-2045 timeframe. Specifically, the Los Angeles Department of Water and Power's (LADWP) Scattergood Modernization project includes plans to have a hydrogen-ready combustion turbine in place when the 346-MW combined cycle plant (potential for up to 830 MW) begins initial operations in 2029. LADWP foresees the plant running on 100 percent electrolytic hydrogen by 2035.

In addition, LADWP also has an agreement in place to purchase electricity from the Intermountain Power Agency project (IPA) in Utah. IPA is replacing an existing 1.8-GW coal-fired EGU with an 840-MW combined cycle turbine that developers expect to initially co-fire 30 percent electrolytic hydrogen in 2025 and 100 percent hydrogen by 2045.

In Florida, NextEra Energy has announced plans to operate 16 GW of existing natural gas-fired combustion turbines with electrolytic hydrogen as part of the utility's Zero Carbon Blueprint to be carbon-free by 2045.

Duke Energy Corporation, which operates 33 gas-fired plants across the Midwest, the Carolinas, and Florida, has outlined plans for full hydrogen capabilities throughout its future turbine fleet: “All natural gas units built after 2030 are assumed to be convertible to full hydrogen capability. After 2040, only peaking units that are fully hydrogen capable are assumed to be built.”

https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.

https://www.forbes.com/sites/mitsubishiheavyindustries/2021/07/30/eager-to-become-hydrogen-ready-power-plants-turn-to-dual-fuel-turbines/?sh=38ddea053476.

https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.

https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf.

In addition to those three utility announcements, several merchant generators operating in wholesale markets are also signaling their intent to ramp up hydrogen co-firing levels after initial 30 percent co-firing phases. The Cricket Valley Energy Center (CVEC) in New York is retrofitting its combined cycle power plant starting in 2022 as a first step toward the conversion to a 100 percent hydrogen fuel capable plant. CVEC announcements did not have specific dates for 100 percent electrolytic hydrogen firing but indicated in its announcement that New York has mandated achieving a zero-emission electricity sector by 2040.

The Long Ridge Energy Terminal in Ohio, which is has successfully co-fired a 5 percent hydrogen blend at its 485-MW combined cycle plant, noted its technology has the capability to transition to 100 percent hydrogen over time as its low-GHG fuel supply becomes available.

Constellation Energy, which owns 23 natural gas-fired or dual fuel generators (8.6 GW), is exploring electrolytic hydrogen co-firing across its fleet. It estimated costs for blend levels in the range of 60-100 percent at approximately $100/kW for retrofits and noted that equipment manufacturers are planning 100 percent hydrogen combustion-ready turbines before 2030.

https://www.cricketvalley.com/news/cricket-valley-energy-center-and-ge-sign-agreement-to-help-reduce-carbon-emissions-in-new-york-with-green-hydrogen-fueled-power-plant/.

GE-powered gas-fired plant in Ohio now burning hydrogen (

power-eng.com

Constellation Energy Corporation's Comments on EPA Draft White Paper: Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine Electric Generating Units Docket ID No. EPA-HQ-OAR-2022-0289-0022.

In both the IIJA and the IRA, Congress provided extensive support for the development of hydrogen produced through low-GHG methods. This support includes investment in infrastructure through the IIJA, and the provision of tax credits in the IRA to incentivize the manufacture of hydrogen through low GHG-emitting methods. These incentives are fueling interest in co-firing hydrogen and creating expectations that the availability of low-cost and low-GHG hydrogen will increase in the coming years. These projections are based on a combination of economies of scale as low-GHG production methods expand, the increasing availability of low-cost electricity—largely powered by renewable energy sources and potentially nuclear energy—and learning by doing as more turbine projects are developed.

In developing these proposals, the EPA reviewed in detail the current state of hydrogen co-firing technology and costs. This review is reflected in the BSER discussions later in this preamble and is further detailed in the accompanying RIA and technical support document titled,

Hydrogen in Combustion Turbine Electric Generating Units.

Both documents are included in the rulemaking docket.

F. Recent Changes in the Power Sector

1. Overview

The electric power sector is experiencing a prolonged period of transition and structural change. Since the generation of electricity from coal-fired power plants peaked nearly two decades ago, the power sector has changed at a rapid pace. Today, natural gas-fired power plants provide the largest share of net generation, coal-fired power plants provide a significantly smaller share than in the recent past, renewable energy provides a steadily increasing share, and as new technologies enter the marketplace, power producers continue to replace aging assets with more efficient and lower cost alternatives.

These developments have significant implications for the types of controls that the EPA proposes to determine qualify as the BSER for different types of fossil fuel-fired EGUs. For example, many utilities and power plant operators have announced plans to voluntarily cease operating coal-fired power plants in the near future, in some cases after operating them at low levels for a several-year period. Industry stakeholders have requested that the EPA structure this rule to avoid imposing costly control obligations on coal-fired power plants that have announced plans to voluntarily cease operations, and the EPA proposes to accommodate those requests. In addition, the EPA recognizes that utilities and power plant operators are building new natural gas-fired combustion turbines with plans to operate them at varying levels of utilization, in coordination with other existing and expected new energy sources. These patterns of operation are important for the type of controls that the EPA is proposing as the BSER for these turbines.

This section discusses the recent trends in the power sector. It also includes a summary of the provisions and incentives included in recent Federal legislation that will impact the power sector as well as State actions and commitments by power producers to reduce GHG emissions. The section

concludes with projections of future trends in power sector generation.

2. Broad Trends Within the Power Sector

For more than a decade, the power sector has experienced substantial transition and structural change, both in terms of the mix of generating capacity and in the share of electricity generation supplied by different types of EGUs. These changes are the result of multiple factors, including normal replacements of older EGUs; changes in electricity demand across the broader economy; growth and regional changes in the U.S. population; technological improvements in electricity generation from both existing and new EGUs; changes in the prices and availability of different fuels; State and Federal policy; the preferences and purchasing behaviors of end-use electricity consumers; and substantial growth in electricity generation from renewable sources.

One of the most important developments of this transition has been the evolving economics of the power sector. Specifically, the existing fleet of coal-fired EGUs continues to age and become more costly to maintain and operate. At the same time, the supply and availability of natural gas has increased significantly, and its price has held relatively low. For the first time, in April 2015, natural gas surpassed coal in monthly net electricity generation and since that time has maintained its position as the primary fossil fuel for base load energy generation, for peaking applications, and for balancing renewable generation.

Additionally, there has been increased generation from investments in zero- and low-GHG emission energy technologies spurred by technological advancements, declining costs, State and Federal policies, and most recently, the IIJA and the IRA. For example, the IIJA provides investments and other policies to help commercialize, demonstrate, and deploy technologies such as small modular nuclear reactors, long-duration energy storage, regional clean hydrogen hubs, carbon capture and storage and associated infrastructure, advanced geothermal systems, and advanced distributed energy resources (DER) as well as more traditional wind and solar resources. The IRA provides numerous tax and other incentives to directly spur deployment of clean energy technologies. Particularly relevant to these proposals, the incentives in the IRA,

which are discussed in detail later in this section of the preamble, support the expansion of technologies, such as CCS and hydrogen technologies, that reduce GHG emissions from fossil-fired units.

U.S. Energy Information Administration (EIA). Monthly Energy Review and Short-Term Energy Outlook, March 2016.

https://www.eia.gov/todayinenergy/detail.php?id=25392.

U.S. Department of Energy (DOE). August 2022.

The Inflation Reduction Act Drives Significant Emissions Reductions and Positions America to Reach Our Climate Goals. https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.

The ongoing transition of the power sector is illustrated by a comparison of data between 2010 and 2021. In 2010, approximately 70 percent of the electricity provided to the U.S. grid was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share. By 2021, fossil fuel net generation was approximately 60 percent, less than the share in 2010 despite electricity demand remaining relatively flat over this same time period. Moreover, the share of fossil generation supplied by coal-fired EGUs fell from 46 percent in 2010 to 23 percent in 2021 while the share supplied by natural gas-fired EGUs rose from 23 to 37 percent during the same period. In absolute terms, coal-fired generation declined by 51 percent while natural gas-fired generation increased by 64 percent. This reflects both the increase in natural gas capacity as well as an increase in the utilization of new and existing gas-fired EGUs. The combination of wind and solar generation also grew from 2 percent of the electric power sector mix in 2010 to 12 percent in 2021.

U.S. Energy Information Administration (EIA).

Annual Energy Review,

table 8.2b Electricity net generation: electric power sector.

https://www.eia.gov/totalenergy/data/annual/.

The broad trends throughout the power sector can also be seen in the number of commitments and announced plans of many EGU owners and operators across the industry to decarbonize—spanning all types of companies in all locations. Moreover, State governments, which traditionally regulate investment decisions regarding electricity generation, have implemented their own policies to reduce GHG emissions from power generation.

Additional analysis of the utility power sector, including projections of future power sector behavior and the impacts of these proposed rules, is discussed in more detail in section XV of this preamble, in the accompanying RIA, and in the

Power Sector Trends

technical support document (TSD). The latter two documents are available in the rulemaking docket. Consistent with analyses done by other energy modelers, the RIA and TSD demonstrate that the sector trend of moving away from coal-fired generation is likely to continue and that non-emitting technologies may eventually displace certain natural gas-fired combustion turbines.

3. Trends in Coal-Fired Generation

Coal-fired steam generating units have historically been the nation's foremost source of electricity, but coal-fired generation has declined steadily since its peak approximately 20 years ago.

Construction of new coal-fired steam generating units was at its highest between 1967 and 1986, with approximately 188 GW (or 9.4 GW per year) of capacity added to the grid during that 20-year period.

The peak annual capacity addition was 14 GW, which was added in 1980. These coal-fired steam generating units operated as base load units for decades. However, beginning in 2005, the U.S. power sector—and especially the coal-fired fleet—began experiencing a period of transition that continues today. Many of the older coal-fired steam generating units built in the 1960s, 1970s, and 1980s have retired and/or have experienced significant reductions in net generation due to cost pressures and other factors. Some of these coal-fired steam generating units repowered with combustion turbines and natural gas.

And with no new coal-fired steam generating units commencing construction in more than a decade—and with the EPA unaware of any plans by any companies to construct a new coal-fired EGU—much of the fleet that remains is aging, expensive to operate and maintain, and increasingly uncompetitive relative to other sources of generation in many parts of the country.

U.S. Energy Information Administration (EIA). Today in Energy.

Natural gas expected to surpass coal in mix of fuel used for U.S. power generation in 2016.

March 2016.

https://www.eia.gov/todayinenergy/detail.php?id=25392.

U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form EIA-860M, Inventory of Operating Generators and Inventory of Retired Generators, March 2022.

https://www.eia.gov/electricity/data/eia860m/.

U.S. Energy Information Administration (EIA). Today in Energy.

More than 100 coal-fired plants have been replaced or converted to natural gas since 2011.

August 2020.

https://www.eia.gov/todayinenergy/detail.php?id=44636.

Since 2010, the power sector's total installed capacity

has increased by

144 GW (14 percent), while coal-fired steam generating unit capacity has declined by 107 GW. This reduction in coal-fired steam generating unit capacity was offset by an increase in total installed wind capacity of 93 GW, natural gas capacity of 84 GW, and an increase in utility-scale solar capacity of 60 GW during the same period. Additionally, significant amounts of DER solar (33 GW) were also added. Two-thirds or more of these changes were in the most recent 6 years of this period. From 2015-2021, coal capacity was reduced by 70 GW and this reduction in capacity was offset by a net increase of 60 GW of wind capacity, 52 GW of natural gas capacity, and 47 GW of utility-scale solar capacity. Additionally, 23 GW of DER solar were also added from 2015 to 2021.

This includes generating capacity at EGUs primarily operated to supply electricity to the grid and combined heat and power (CHP) facilities classified as Independent Power Producers and excludes generating capacity at commercial and industrial facilities that does not operate primarily as an EGU. Natural gas information reflects data for all generating units using natural gas as the primary

fossil heat source unless otherwise stated. This includes combined cycle, simple cycle, steam, and miscellaneous (<1 percent).

At the end of 2021, there were more than 500 EGUs totaling 212 GW of coal-fired capacity remaining in the U.S. Although much of the fleet of coal-fired steam generating units has historically operated as base load, there can be notable differences in design and operation across various facilities. For example, coal-fired steam generating units smaller than 100 MW comprise 18 percent of the total number of coal-fired units, but only 2 percent of total coal-fired capacity.

Moreover, average annual capacity factors for coal-fired steam generating units have declined from 67 to 49 percent since 2010,

indicating that a larger share of units are operating in non-base load fashion.

U.S. Environmental Protection Agency. National Electric Energy Data System (NEEDS) v6. October 2022.

https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.

U.S. Energy Information Administration (EIA). Electric Power Annual 2021, table 1.2.

Older power plants also tend to become uneconomic over time as they become more costly to maintain and operate,

especially when competing for dispatch against newer and more efficient generating technologies that have lower operating costs. The average coal-fired power plant that retired between 2015 and 2021 was more than 50 years old, and 65 percent of the remaining fleet of coal-fired steam generating units will be 50 years old or more within a decade.

To further illustrate this trend, the existing coal-fired steam generating units older than 40 years represent 71 percent (154 GW)

of the total remaining capacity. In fact, more than half (118 GW) of the coal-fired steam generating units still operating have already announced retirement dates prior to 2040.

As discussed further in this section, projections anticipate that this trend will continue.

U.S. Energy Information Administration (EIA). U.S. coal plant retirements linked to plants with higher operating costs. December 2019.

https://www.eia.gov/todayinenergy/detail.php?id=42155.

eGRID 2020 (January 2022 release from EPA eGRID website). Represents data from generators that came online between 1950 and 2020 (inclusive); a 71-year period. Full eGRID data includes generators that came online as far back as 1915.

U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form-860M, Inventory of Operating Generators and Inventory of Retired Generators. August 2022.

https://www.eia.gov/electricity/data/eia860m/.

U.S. Environmental Protection Agency. National Electric Energy Data System (NEEDS) v6. October 2022.

https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.

The reduction in coal-fired generation by electric utilities is also evident in data for annual U.S. coal production, which reflects reductions in international demand as well. In 2008, annual coal production peaked at nearly 1,200 million short tons (MMst) followed by sharp declines in 2015 and 2020.

In 2015, less than 900 MMst were produced, and in 2020, the total dropped to 535 MMst, the lowest output since 1965.

U.S. Energy Information Administration (EIA). Annual Coal Report. Table ES-1. October 2022.

https://eia.gov/coal/annual/pdf/tableES1.pdf.

4. Trends in Natural Gas-Fired Generation

In the lower 48 states, most combustion turbine EGUs burn natural gas, and some have the capability to fire distillate oil as backup for periods when natural gas is not available, such as when residential demand for natural gas is high during the winter. Areas of the country without access to natural gas often use distillate oil or some other locally available fuel. Combustion turbines have the capability to burn either gaseous or liquid fossil fuels, including but not limited to kerosene, naphtha, synthetic gas, biogases, liquified natural gas (LNG), and hydrogen.

Natural gas consists primarily of methane, and after the raw gas is extracted from the ground, it is processed to remove impurities and to separate the methane from other gases and natural gas liquids to produce pipeline quality gas.

This gas is sent to intermediate storage facilities prior to being piped through transmission feeder lines to a distribution network on its path to storage facilities or end users. During the past 20 years, advances in hydraulic fracturing (

i.e.,

fracking) and horizontal drilling techniques have opened new regions of the U.S. to gas exploration.

U.S. Energy Information Administration (EIA). Natural Gas Explained. December 2022.

https://www.eia.gov/energyexplained/natural-gas/.

According to the U.S. Energy Information Administration (EIA), annual natural gas marketed production in the U.S. remained consistent at approximately 20 trillion cubic feet (Tcf) from the 1970s to the early 2000s. However, since 2005, annual natural gas marketed production has steadily increased and approached 35 Tcf in 2021, which is an average of approximately 94.6 billion cubic feet per day.

Thirty-four states produce natural gas with Texas (24.6 percent), Pennsylvania (21.8 percent), Louisiana (9.9 percent), West Virginia (7.4 percent), and Oklahoma (6.7 percent) accounting for approximately 70 percent of total production. Natural gas production exceeded consumption in the U.S. for the first time in 2017.

U.S. Energy Information Administration (EIA). Natural gas explained. Where our natural gas comes from.

https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php.

As the production of natural gas has increased, the annual average price has declined during the same period.

In 2008, U.S. natural gas prices peaked at $13.39 per million British thermal units ($/MMBtu) for residential customers. By 2020, the price was $10.45/MMBtu. The decrease in average annual natural gas prices can also been seen in city gate prices (

i.e.,

a point or measuring station where natural gas is transferred from long-distance pipelines to a local distribution company), which peaked in 2008 at $8.85/MMBtu. By 2020, city gate prices were $3.30/MMBtu. An equivalent $/MMBtu basis is a common way to compare natural gas and coal fuel prices. For example, the price of Henry Hub natural gas in July 2022 was $7.39/MMBtu while the spot price of Central Appalachian coal was $7.25/MMBtu for the same month. However, this method of fuel price comparison based on equivalent energy content does not reflect differences in energy conversion efficiency (

i.e.,

heat rate) and other factors among different types of generators. Because natural gas-fired combustion turbines are more efficient than coal-fired steam units, any fuel cost comparison should include an efficiency basis (dollar per megawatt-hour) to the equivalent energy content. For illustrative purposes, an EIA comparison based on this method showed that the Henry Hub natural gas

price in July 2022 was $59.18/MWh and the price for Central Appalachian coal was $78.25/MWh for the same month.

U.S. Energy Information Administration (EIA).

Natural Gas Annual,

September 2021.

https://www.eia.gov/energyexplained/natural-gas/prices.php.

U.S. Energy Information Administration (EIA).

Electric Monthly Update.

September 23. 2022. Report derived from Bloomberg Energy. EIA notes that the competition between coal and natural gas to produce electricity is complex, involving delivered prices and emission costs, the terms of fuel supply contracts, and the workings of fuel markets.

There has been significant expansion of the natural gas-fired EGU fleet since 2000, coinciding with efficiency improvements of combustion turbine technologies, increased availability of natural gas, increased demand for flexible generation to support the expanding capacity of renewable energy resources, and declining costs for all three elements. According to data from EIA, annual capacity additions for natural gas-fired EGUs peaked between 2000 and 2006, with more than 212 GW added to the grid during this period. Of this total, approximately 147 GW (70 percent) were combined cycle capacity and 65 GW were simple cycle capacity.

From 2007 to 2021, more than 125 GW of capacity were constructed and approximately 78 percent of that total were combined cycle EGUs. This figure represents an average of almost 4.2 GW of new combustion turbine generation capacity per year. In 2021, the net summer capacity of combustion turbine EGUs totaled 413 GW, with 281 GW being combined cycle generation and 132 GW being simple cycle generation.

U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form EIA-860M, Inventory of Operating Generators and Inventory of Retired Generators, July 2022.

https://www.eia.gov/electricity/data/eia860m/.

This trend away from coal to natural gas is also reflected in comparisons of annual capacity factors, sizes, and ages of affected EGUs. For example, the annual average capacity factors for natural gas-fired units increased from 28 to 37 percent between 2010 and 2021. And compared with the fleet of coal-fired steam generating units, the natural gas fleet is generally smaller and newer. While 67 percent of the coal-fired steam generating unit fleet capacity is over 500 MW per unit, 75 percent of the gas fleet is between 50 and 500 MW per unit. In terms of the age of the generating units, nearly 50 percent of the natural gas capacity has been in service less than 15 years.

National Electric Energy Data System (NEEDS) v.6.

As explained in greater detail later in this preamble and in the accompanying RIA, future capacity projections for natural gas-fired combustion turbines differ from those highlighted in recent historical trends. The largest source of new generation is from renewable energy and projections show that total natural gas-fired combined cycle capacity is likely to decline after 2030 in response to increased generation from renewables, energy storage, and other technologies, as discussed in section IV.I. Approximately, 86 percent of capacity additions in 2023 are expected to be from non-emitting generation resources including solar, wind, nuclear, and energy storage.

The IRA is likely to accelerate this trend, which is also expected to impact the operation of certain combustion turbines. For example, as the electric output from additional non-emitting generating sources fluctuates daily and seasonally, flexible low and intermediate load combustion turbines will be needed to support these variable sources and provide reliability to the grid. This requires the ability to start and stop quickly and change load more frequently.

U.S. Energy Information Administration (EIA). Today in Energy. More than half of new U.S. electric-generating capacity in 2023 will be solar. February 2023.

https://www.eia.gov/todayinenergy/detail.php?id=55419.

5. Trends in Renewable Generation

Renewable sources of electric generation—especially solar and wind—have expanded in the U.S. during the past decade. This growth has coincided with a reduction in the costs of the technologies, supportive State and Federal policies, and increased consumer demand for low-GHG electricity. In 2021, renewable energy sources produced approximately 20 percent of the nation's net generation, led by wind (9.2 percent), hydroelectric (6.3 percent), solar (2.8 percent), and other sources such as geothermal and biomass (1.7 percent).

U.S. Energy Information Administration (EIA). Monthly Energy Review, table 7.2B Electricity Net Generation: Electric Power Sector, May 2022.

https://www.eia.gov/totalenergy/data/monthly/.

The costs of renewable energy sources have fallen over time due to technological advances, improvements in performance, and increased demand for clean energy. For example, the unsubsidized average levelized cost of wind energy from 1988 to 1999 was $106/MWh and has since declined to $32/MWh in 2021.

The average levelized cost of energy for utility-scale solar photovoltaics has fallen from $227/MWh in 2010 to $33/MWh in 2021.

And the National Renewable Energy Laboratory (NREL) has documented cost decreases of 64, 69, and 82 percent, respectively, for residential-, commercial-, and utility-scale solar installations since 2010.

100

Local, State, and Federal incentives and tax credits have further reduced the cost of renewable energy resources.

U.S. Department of Energy (DOE), Land-Based Wind Market Report: 2022 Edition, 2022.

https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition.

Lawrence Berkeley National Laboratory (LBNL), Utility-Scale Solar Technical Brief, 2022 Edition, September 2022.

https://emp.lbl.gov/utility-scale-solar.

100

https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html.

During the past 15 years, more than 122 GW of wind (primarily onshore) and 61 GW of solar capacity have been constructed, which represent a tripling of wind capacity and a 20-fold increase in solar capacity.

101

Prior to 2007, no more than 2.6 GW of new wind capacity was built in any year, and the wind capacity added from 2000 to 2006 averaged 1.2 GW per year. In 2007, the nation added 5.3 GW of total wind capacity and the annual average was 7.2 GW through 2019. Wind capacity additions peaked in the past 2 years at a total of nearly 29 GW. For solar, the pattern of expansion is similar. For example, from 2000 to 2006, a total of 11 MW of new solar capacity was constructed, and from 2007 to 2011, total capacity additions increased to 1.2 GW. However, from 2012 to 2019, more than 36 GW of solar capacity was built (an average of 4.5 GW per year). And in 2020 and 2021, new solar capacity totaled of 24 GW. In terms of the net operating share of summer capacity in 2021, wind produced 46 percent of all renewable energy while solar generated 21 percent. The remaining electricity generated from renewables included 28 percent from hydroelectric and 5 percent from other sources that include geothermal systems, biogases/biomethane from landfills, woody materials and other biomass, and municipal solid waste.

101

U.S. Energy Information Administration (EIA), Electric Generators Inventory, Form-860M, Inventory of Operating Generators and Inventory of Retired Generators, July 2022.

https://www.eia.gov/electricity/data/eia860m/.

There are also emerging technologies such as battery storage that have demonstrated the ability to further support the development and integration of renewable energy to the grid by balancing variable supply and demand resources. At the end of 2021, there were 331 large-scale battery storage systems operating in the U.S. with a combined capacity of 4.8 GW

(10.7 GWh).

102

In terms of small-scale battery storage, there were 781 MW of reported capacity in 2021, mostly in California.

103

Energy storage costs declined 72 percent between 2015 and 2019,

104

and declining costs have led to additional capacity being installed at each facility, and this increases the duration of each system when operating at maximum output. With 20.8 GW of grid storage already announced for 2023-2025, EIA expects that capacity will more than triple from 7.8 GW in late 2022 to approximately 30 GW by the end of 2025.

105

102

U.S. Energy Information Administration (EIA). Annual Electric Generator Report, 2021 Form EIA-860.

https://www.eia.gov/electricity/data/eia860/.

103

U.S. Energy Information Administration (EIA). Annual Electric Power Industry Report, 2021 Form EIA-861.

https://www.eia.gov/electricity/data/eia861/.

104

U.S. Energy Information Administration (EIA). Annual Electric Generator Report, 2019 Form EIA-860.

https://www.eia.gov/analysis/studies/electricity/batterystorage/.

105

U.S. Energy Information Administration (EIA). Today in Energy.

U.S. battery storage capacity will increase significantly by 2025.

December 2022.

https://www.eia.gov/todayinenergy/detail.php?id=54939.

6. Trends in Nuclear Generation

The U.S. power sector continues to rely on nuclear sources of energy for a consistent portion of net generation. Since 1990, nuclear energy has provided about 20 percent of the nation's electricity, and 92 reactors were operating at 54 nuclear power plants in 28 states in 2022.

106

U.S. Energy Information Administration (EIA).

Electric Generators Inventory, Form-860M, Inventory of Operating Generators and Inventory of Retired Generators.

August 2022.

https://www.eia.gov/electricity/data/eia860m/.

It should be noted that despite the consistent output from nuclear power plants over time, the number of operating reactors has recently declined. The average retirement age for a nuclear reactor is 44 years and the average age of the remaining nuclear fleet is currently 42 years, although age is only one consideration for determining when a nuclear plant may retire. For example, nuclear generating units at Dominion Generation's Surry plant, Florida Power & Light's Turkey Point plant, and Constellation Energy's Peach Bottom plant applied to the Nuclear Regulatory Commission (NRC) for second 20-year license renewals and subsequent renewed licenses were granted for six units, although four of the six units have not had their license terms extended beyond the periods of their first renewed licenses and are undergoing further environmental review.

107

Others who have applied to the NRC for a second 20-year license renewal include Dominion for its North Anna units 1 and 2; NextEra Energy for its Point Beach units 1 and 2; Duke Energy Carolinas for its Oconee units 1, 2, and 3; Florida Power & Light for its St. Lucie units 1 and 2; and Northern States Power Company for its Monticello unit 1. If granted, these additional licenses would also extend the lifespans of these units well past the 42-year average. Recent State and Federal policies, including the DOE's $6 billion Civilian Nuclear Credit program enacted by the IIJA and the 45U tax credit (discussed below), are intended to support the continued operation of existing nuclear power plants.

107

U.S. Nuclear Regulatory Commission (NRC). Status of Subsequent License Renewal Applications. April 2023.

https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html.

There is also interest in the next generation of nuclear technologies. Small modular nuclear reactors, which can provide both firm dispatchable power and load-following capabilities to balance greater volumes of variable renewable generation, could play a role in future energy generation. The NRC has issued a final rule certifying the first small modular reactor design.

108

Expectations with respect to output from advanced nuclear generation vary, from negligible on the low end to as high as between 1,400 and 3,600 terawatt-hours per year by 2050.

109

According to one survey by the Nuclear Energy Institute, utilities are currently considering building more than 90 GW of small modular nuclear reactors by 2050.

110

108

88 FR 3287 (January 19, 2023).

109

Stein, A., Messinger, J., Wang, S., Lloyd, J., McBride, J., Franovich, R. (July 6, 2022). “

Advancing Nuclear Energy: Evaluating Deployment, Investment, and Impact in America's Clean Energy Future.

” Breakthrough Institute.

https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf.

110

Derr, E. (July 29, 2022).

Energy Studies and Models Show Advanced Nuclear as the Backbone of Our Carbon-Free Future.

Nuclear Energy Institute (NEI).

https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear.

G. GHG Emissions From Fossil Fuel-Fired EGUs

The principal GHGs that accumulate in the Earth's atmosphere above pre-industrial levels because of human activity are CO

, CH

, N

O, HFCs, PFCs, and SF

. Of these, CO

is the most abundant, accounting for 80 percent of all GHGs present in the atmosphere. This abundance of CO

is largely due to the combustion of fossil fuels by the transportation, electricity, and industrial sectors.

111

U.S. Environmental Protection Agency (EPA). Overview of greenhouse gas emissions. July 2021.

https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.

The amount of CO

emitted from fossil fuel-fired EGUs depends on the carbon content of the fuel and the size and efficiency of the EGU. Different fuels emit different amounts of CO

in relation to the energy they produce when combusted. The amount of CO

produced when a fuel is burned is a function of the carbon content of the fuel. The heat content, or the amount of energy produced when a fuel is burned, is mainly determined by the carbon and hydrogen content of the fuel. For example, in terms of pounds of CO

emitted per million British thermal units of energy produced, when combusted, natural gas is the lowest compared to other fossil fuels at 117 lb CO

/MMBtu.

112 113

The average for coal is 216 lb CO

/MMBtu, but varies between 206 to 229 lb CO

/MMBtu by type (

e.g.,

anthracite, lignite, subbituminous, and bituminous).

114

The value for petroleum products such as diesel fuel and heating oil is 161 lb CO

/MMBtu.

112

Natural gas is primarily CH

, which has a higher hydrogen to carbon atomic ratio, relative to other fuels, and thus, produces the least CO

per unit of heat released. In addition to a lower CO

emission rate on a lb/MMBtu basis, natural gas is generally converted to electricity more efficiently than coal. According to EIA, the 2020 emissions rate for coal and natural gas were 2.23 lb CO

/kWh and 0.91 lb CO

/kWh, respectively.

www.eia.gov/tools/faqs/faq.php?id=74&t=11.

113

Values reflect the carbon content on a per unit of energy produced on a higher heating value (HHV) combustion basis and are not reflective of recovered useful energy from any particular technology.

114

Energy Information Administration (EIA).

Carbon Dioxide Emissions Coefficients. https://www.eia.gov/environment/emissions/co2_vol_mass.php.

The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks

115

(the U.S. GHG Inventory) to comply with commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which includes recent trends, is organized by industrial sectors. It presents total U.S. anthropogenic emissions and sinks

116

of GHGs, including CO

emissions, for the years 1990-2020.

115

U.S. Environmental Protection Agency (EPA).

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. https://cfpub.epa.gov/ghgdata.

116

Sinks are a physical unit or process that stores GHGs, such as forests or underground or deep-sea reservoirs of carbon dioxide.

According to the latest inventory, in 2021, total U.S. GHG emissions were 6,340 million metric tons of carbon dioxide equivalent (MMT CO

e). The transportation sector (28.5 percent) was the largest contributor to total U.S. GHG emissions, followed by the power sector (25.0 percent) and industrial sources

(23.5 percent). In terms of annual CO

emissions, the power sector was responsible for 30.6 percent (1,541 MMT CO

e) of the nation's 2021 total.

emissions from the power sector have declined by 36 percent since 2005 (when the power sector reached annual emissions of 2,400 MMT CO

, its historical peak to date).

117

The reduction in CO

emissions can be attributed to the power sector's ongoing trends away from carbon-intensive coal-fired generation and toward more natural gas-fired and renewable sources. In 2005, CO

emissions from coal-fired EGUs alone measured 1,983 MMT.

118

This total dropped to 1,351 MMT in 2015 and reached 974 MMT in 2019, the first time since 1978 that coal-fired CO

emissions were below 1,000 MMT. In 2020, emissions of CO

from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909 MMT due to increased demand. By contrast, CO

emissions from natural gas-fired generation have almost doubled since 2005, increasing from 319 MMT to 613 MMT in 2021, and CO

emissions from petroleum products (

i.e.,

distillate fuel oil, petroleum coke, and residual fuel oil) declined from 98 MMT in 2005 to 18 MMT in 2021.

117

U.S. Environmental Protection Agency (EPA).

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.

118

U.S. Energy Information Administration (EIA). Monthly Energy Review, table 11.6. September 2022.

https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.

When the EPA finalized the Clean Power Plan (CPP) in October 2015, the Agency projected that, as a result of the CPP, the power sector would reduce its annual CO

emissions to 1,632 MMT by 2030, or 32 percent below 2005 levels (2,400 MMT).

119

Instead, even in the absence of Federal regulations for existing EGUs, annual CO

emissions from sources covered by the CPP had fallen to 1,540 MMT by the end of 2021, a nearly 36 percent reduction below 2005 levels. The power sector achieved a deeper level of reductions than forecast under the CPP and approximately a decade ahead of time. By the end of 2015, several months after the CPP was finalized, those sources already had achieved CO

emission levels of 1,900 MMT, or approximately 21 percent below 2005 levels. However, progress in emission reductions is not uniform across all states and so Federal policies play an essential role. As discussed earlier in this section, the power sector remains a leading emitter of CO

in the U.S., and, despite the emission reductions since 2005, current CO

levels continue to endanger human health and welfare. Further, as sources in other sectors of the economy turn to electrification to decarbonize, future CO

reductions from fossil fuel-fired EGUs have the potential to take on added significance and increased benefits.

119

80 FR 63662 (October 23, 2015).

The Legislative, Market, and State Law Context

Recent Legislation Impacting the Power Sector

On November 15, 2021, President Biden signed the IIJA

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(also known as the Bipartisan Infrastructure Law), which allocated more than $65 billion in funding via grant programs, contracts, cooperative agreements, credit allocations, and other mechanisms to develop and upgrade infrastructure and expand access to clean energy technologies. Specific objectives of the legislation are to improve the nation's electricity transmission capacity, pipeline infrastructure, and increase the availability of low-GHG fuels. Some of the IIJA programs

121

that will impact the utility power sector include: $16.5 billion to build and upgrade the nation's elect

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