Home/Federal/Federal Register/2023-10141

Proposed Rule2023-10141

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

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Published

May 23, 2023

Issuing agencies

Environmental Protection Agency

Abstract

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.

Full Text

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[Federal Register Volume 88, Number 99 (Tuesday, May 23, 2023)]
[Proposed Rules]
[Pages 33240-33420]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2023-10141]

[[Page 33239]]

Vol. 88

Tuesday,

No. 99

May 23, 2023

Part III

Environmental Protection Agency

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40 CFR Part 60

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; Proposed Rule

Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed
Rules

[[Page 33240]]

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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.

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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:
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov">https://www.regulations.gov</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#a3c28ec2cdc78ed18ec7ccc0c8c6d7e3c6d3c28dc4ccd5">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2023-0072 in the subject line of the message.
<bullet> Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2023-0072.
<bullet> 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.
<bullet> 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 <a href="https://www.regulations.gov">https://www.regulations.gov</a>, 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:
<a href="/cdn-cgi/l/email-protection#fc9a99909092998ed29f948e958f88959d92bc998c9dd29b938a">[email&#160;protected]</a> 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: <a href="/cdn-cgi/l/email-protection#47332f282a37342829692b2e34260722372669202831">[email&#160;protected]</a>.

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 <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>.
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 <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a> or contact the public hearing team
at (888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#40131010043035222c292328252132292e27002530216e272f36">[email&#160;protected]</a>. 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: <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>.
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 <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>. 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 <a href="/cdn-cgi/l/email-protection#faa9aaaabe8a8f98969399929f9b8893949dba9f8a9bd49d958c">[email&#160;protected]</a> to
determine if there are any updates. The EPA does not intend to publish
a document in the Federal Register announcing updates.

[[Page 33241]]

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 <a href="http://Regulations.gov">Regulations.gov</a> 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 <a href="https://www.regulations.gov">https://www.regulations.gov</a> (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 <a href="https://www.regulations.gov">https://www.regulations.gov</a> 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 <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a> for additional submission methods; the full EPA
public comment policy; information about CBI or multimedia submissions;
and general guidance on making effective comments.
The <a href="https://www.regulations.gov">https://www.regulations.gov</a> 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
<a href="https://www.regulations.gov">https://www.regulations.gov</a>, 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 <a href="https://www.regulations.gov">https://www.regulations.gov</a>. 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 <a href="/cdn-cgi/l/email-protection#a8c7c9d9d8dbcbcac1e8cdd8c986cfc7de">[email&#160;protected]</a> 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 <a href="/cdn-cgi/l/email-protection#57383626272434353e1732273679303821">[email&#160;protected]</a> 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
CO<INF>2</INF> 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<INF>2</INF>e million metric tons of carbon dioxide equivalent
MW megawatt
MWh megawatt-hour

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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
NO<INF>X</INF> 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.\1\ 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

[[Page 33243]]

achieve reductions in GHG emissions from the power sector.
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\1\ 74 FR 66496 (December 15, 2009).
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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.\2\ These emissions are almost entirely the result
of the combustion of fossil fuels in the EGUs that are the subjects of
these proposals.
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\2\ <a href="https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions">https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions</a>.
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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 v. 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.

[[Page 33244]]

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<INF>2</INF>/MMBtu
to 160 lb CO<INF>2</INF>/MMBtu, depending on the type of fuel
combusted.\3\ 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.
---------------------------------------------------------------------------

\3\ 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<INF>2</INF>/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<INF>2</INF> 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<INF>2</INF>/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<INF>2</INF>/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<INF>2</INF>/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<INF>2</INF>/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<INF>2</INF> with
an associated standard of 90 lb CO<INF>2</INF>/MWh-gross, compliance
with which would be

[[Page 33245]]

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<INF>2</INF>/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<INF>2</INF>/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<INF>2</INF>. 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<INF>2</INF> with an associated degree of emission
limitation of an 88.4 percent reduction in emission rate (lb
CO<INF>2</INF>/MWh-gross basis). As explained in detail in this
proposal, CCS with 90 percent capture of CO<INF>2</INF> 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<INF>2</INF>/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<INF>2</INF>/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<INF>2</INF>/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

[[Page 33246]]

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 \4\ (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.
---------------------------------------------------------------------------

\4\ 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<INF>2</INF>; 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.\5\
---------------------------------------------------------------------------

\5\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/4346">https://www.congress.gov/bill/117th-congress/house-bill/4346</a>.
---------------------------------------------------------------------------

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

[[Page 33247]]

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<INF>X</INF>), sulfur dioxide
(SO<INF>2</INF>), and fine particulate matter (PM<INF>2.5</INF>). 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<INF>2.5</INF> for a large majority
of the nation's population, as well as reductions in ambient
PM<INF>2.5</INF> 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<INF>2.5</INF> and ozone exposures are small relative
to baseline levels, and although disparities in PM<INF>2.5</INF> 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.'' \6\
---------------------------------------------------------------------------

\6\ Carbon Capture, Utilization, and Sequestration Guidance, 87
FR 8808, 8809 (February 16, 2022), <a href="https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf">https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf</a>.
---------------------------------------------------------------------------

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

[[Page 33248]]

EPA's Greenhouse Gas Reporting Program; and safety regulations for
CO<INF>2</INF> 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 <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>. 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 <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>.

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

[[Page 33249]]

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).\7\ 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<INF>2</INF>), methane (CH<INF>4</INF>),
nitrous oxide (N<INF>2</INF>O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF<INF>6</INF>)--
``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).
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\7\ 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 \8\
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).
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\8\ 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).
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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).\9\ 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).
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\9\ In describing these 2016 Findings in these proposals, the
EPA is neither reopening nor revisiting them.
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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.\10\
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

[[Page 33250]]

globally and in the U.S. These assessments include:
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\10\ See later in this section for specific examples. An
additional resource for indicators can be found at <a href="https://www.epa.gov/climate-indicators">https://www.epa.gov/climate-indicators</a>.
---------------------------------------------------------------------------

<bullet> U.S. Global Change Research Program's (USGCRP) 2016
Climate and Health Assessment \11\ and 2017-2018 Fourth National
Climate Assessment (NCA4).12 13
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\11\ 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.
\12\ 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.
\13\ 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.
---------------------------------------------------------------------------

<bullet> Intergovernmental Panel on Climate Change (IPCC) 2018
Global Warming of 1.5 [deg]C,\14\ 2019 Climate Change and Land,\15\ and
the 2019 Ocean and Cryosphere in a Changing Climate \16\ assessments,
as well as the 2021 IPCC Sixth Assessment Report (AR6).17 18
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\14\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]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.
P[eacute]an, 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.)].
\15\ 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.)].
\16\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere
in a Changing Climate [H.-O. P[ouml]rtner, D.C. Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegr[inodot][acute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama,
N.M. Weyer (eds.)].
\17\ 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[acute]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. Yelekci, R. Yu and B. Zhou (eds.)].
Cambridge University Press.
\18\ IPCC, 2022: Summary for Policymakers [H.-O. P[ouml]rtner,
D.C. Roberts, E.S. Poloczanska, K. Mintenbeck, M. Tignor, A.
Alegr[iacute]a, M. Craig, S. Langsdorf, S. L[ouml]schke, V.
M[ouml]ller, 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. P[ouml]rtner, D.C. Roberts, M. Tignor, E.S.
Poloczanska, K. Mintenbeck, A. Alegr[iacute]a, M. Craig, S.
Langsdorf, S. L[ouml]schke, V. M[ouml]ller, 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.
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<bullet> The National Academy of Sciences (NAS) 2016 Attribution of
Extreme Weather Events in the Context of Climate Change,\19\ 2017
Valuing Climate Damages: Updating Estimation of the Social Cost of
Carbon Dioxide,\20\ and 2019 Climate Change and Ecosystems \21\
assessments.
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\19\ 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.
<a href="https://dio.org/10.17226/21852">https://dio.org/10.17226/21852</a>.
\20\ 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. <a href="https://doi.org/10.17226/24651">https://doi.org/10.17226/24651</a>.
\21\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. <a href="https://doi.org/10.17226/25504">https://doi.org/10.17226/25504</a>.
---------------------------------------------------------------------------

<bullet> National Oceanic and Atmospheric Administration's (NOAA)
annual State of the Climate reports published by the Bulletin of the
American Meteorological Society,\22\ most recently in August of 2022.
---------------------------------------------------------------------------

\22\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
<a href="https://doi.org/10.1175/2022BAMSStateoftheClimate.1">https://doi.org/10.1175/2022BAMSStateoftheClimate.1</a>.
---------------------------------------------------------------------------

<bullet> EPA Climate Change and Social Vulnerability in the United
States: A Focus on Six Impacts (2021).\23\
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\23\ 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.
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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<INF>2</INF>, 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) \24\ and has continued to
rise at a rapid rate. Global average temperature has increased by about
1.1 degrees Celsius ([deg]C) (2.0 degrees Fahrenheit ([deg]F)) in the
2011-2020 decade relative to 1850-1900.\25\ The years 2015-2021 were
the warmest 7 years in the 1880-2020 record according to six different
global surface temperature datasets.\26\ 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.\27\ 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.\28\ 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.\29\ Higher
CO<INF>2</INF> 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.\30\ 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.\31\ 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 \32\ in many
regions.\33\
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\24\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
<a href="https://doi.org/10.1175/2022BAMSStateoftheClimate.1">https://doi.org/10.1175/2022BAMSStateoftheClimate.1</a>.
\25\ IPCC, 2021.
\26\ Blunden, J. and T. Boyer, Eds., 2022.
\27\ IPCC, 2021.
\28\ IPCC, 2021.
\29\ 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.
\30\ IPCC, 2021.
\31\ IPCC, 2021.
\32\ These are drought measures based on soil moisture.
\33\ IPCC, 2021.
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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<INF>2</INF> concentration of
415 ppm is already higher than at any time in the last 2 million
years.\34\ If concentrations exceed 450 ppm, they would likely be
higher

[[Page 33251]]

than at any time in the past 23 million years: \35\ 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<INF>2</INF> 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.\36\
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\34\ IPCC, 2021.
\35\ IPCC, 2013.
\36\ 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. P[eacute]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.
Yelek[ccedil]i, 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.
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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 [deg]C (2.7
[deg]F), from 7 to 20 feet if limited to 2 [deg]C (3.6 [deg]F), and by
60 to 70 feet if warming is allowed to reach 5 [deg]C (9 [deg]F) above
preindustrial levels.\37\ 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<INF>2</INF> being absorbed by the ocean
has resulted in changes in ocean chemistry due to acidification of a
magnitude not seen in 65 million years,\38\ putting many marine
species--particularly calcifying species--at risk.\39\
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\37\ IPCC, 2021.
\38\ IPCC, 2018.
\39\ IPCC, 2021.
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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.\40\ Coral reefs will be at risk for almost complete (99
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from
today (2 [deg]C or 3.6 [deg]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.\41\ 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.\42\
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\40\ USGCRP, 2018.
\41\ IPCC, 2018.
\42\ IPCC, 2022.
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Every additional increment of temperature comes with consequences.
For example, the half degree of warming from 1.5 to 2 [deg]C (0.9
[deg]F of warming from 2.7 [deg]F to 3.6 [deg]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).\43\ 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.\44\
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\43\ IPCC, 2018.
\44\ IPCC, 2021.
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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.\45\ 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.\46\ 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

[[Page 33252]]

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.\47\
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\45\ USGCRP, 2018.
\46\ NIFC (National Interagency Fire Center). 2022. Total
wildland fires and acres (1983-2020). Accessed November 2022.
<a href="https://www.nifc.gov/sites/default/files/document-media/TotalFires.pdf">https://www.nifc.gov/sites/default/files/document-media/TotalFires.pdf</a>.
\47\ USGCRP, 2018.
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of CO<INF>2</INF>
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) \48\ and cause ocean
acidification. Nitrous oxide depletes the levels of protective
stratospheric ozone.\49\ 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.\50\
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\48\ 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, <a href="https://dx.doi.org/10.7930/J0ZP4417">https://dx.doi.org/10.7930/J0ZP4417</a>.
\49\ WMO (World Meteorological Organization), Scientific
Assessment of Ozone Depletion: 2018, Global Ozone Research and
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland,
2018.
\50\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik,
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air
Quality. In Impacts, Risks, and Adaptation in the United States:
Fourth National Climate Assessment, Volume II [Reidmiller, D.R.,
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018.
CH13.
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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.\51\ 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.\52\ 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 \53\ for more details.
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\51\ 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 <a href="https://www.epa.gov/cira/fredi">https://www.epa.gov/cira/fredi</a>. Documentation has been subject to both a
public review comment period and an independent expert peer review,
following EPA peer-review guidelines.
\52\ (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. <a href="https://doi.org/10.1007/s10584-021-03048-6">https://doi.org/10.1007/s10584-021-03048-6</a>, (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.
\53\ 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 <a href="https://www.epa.gov/cira/fredi">https://www.epa.gov/cira/fredi</a>.
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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

[[Page 33253]]

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 \54\ in the event of unexpected changes in the availability of
other generators.
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\54\ 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).
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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 \55\ 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; \56\ in others, individual utilities \57\ coordinate
the operations of their generation and transmission to balance the
system across their respective service territories.
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\55\ 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 <a href="https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf">https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf</a>.
\56\ For example, PJM Interconnection, LLC, New York Independent
System Operator (NYISO), Midwest Independent System Operator (MISO),
California Independent System Operator (CAISO), etc.
\57\ For example, Los Angeles Department of Power and Water,
Florida Power and Light, etc.
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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.\58\ Fossil fuel-fired EGUs
include the steam generating units and stationary combustion turbines
that are the subject of these proposed regulations.
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\58\ U.S. Energy Information Administration (EIA). Electric
Power Monthly, Table 1.1 and Form EIA-860M, July 2022. <a href="https://www.eia.gov/electricity/data/php">https://www.eia.gov/electricity/data/php</a>.
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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<INF>2</INF>), 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.\59\
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\59\ 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

[[Page 33254]]

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.'' \60\
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\60\ 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.
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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<INF>2</INF> from EGUs. CCS has
three major components: CO<INF>2</INF> capture, transportation, and
sequestration/storage. Generally, the capture processes most applicable
to combustion turbines and utility boilers remove CO<INF>2</INF> from
the exhaust gas after combustion. The exhaust gases from most
combustion processes are at atmospheric pressure with relatively low
concentrations of CO<INF>2</INF>. Most post-combustion capture systems
utilize liquid solvents (most commonly amine-based) in a scrubber
column to absorb the CO<INF>2</INF> from the flue gas.\61\ The
CO<INF>2</INF>-rich solvent is then regenerated by heating the solvent
to release the captured CO<INF>2</INF>. The high purity CO<INF>2</INF>
is then compressed and transported, generally through pipelines, to a
site for geologic sequestration (i.e., the long-term containment of
CO<INF>2</INF> in subsurface geologic formations).\62\ 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<INF>2</INF> capture,
excluding any tax credits, from coal-fired power generation is
projected to fall by 50 percent by 2025 compared to 2010.\63\ 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.
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\61\ Post-combustion CO<INF>2</INF> capture is most common, but
as discussed later in this preamble, there are also pre-combustion
CO<INF>2</INF> capture options available and applicable to the power
sector.
\62\ 40 CFR 261.4(h).
\63\ Technology Readiness and Costs of CCS (2021). Global CCS
Institute. <a href="https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf">https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf</a>.
_____________________________________-

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<INF>2</INF> capture rates of 90 percent using an amine-
based post-combustion capture system retrofitted to the existing steam
generating unit.\64\ Amine-based carbon capture has also been
demonstrated at AES's Warrior Run (Cumberland, Maryland) and Shady
Point (Panama, Oklahoma) coal-fired power plants.\65\
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\64\ 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. <a href="https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191">https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191</a>.
\65\ 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<INF>2</INF> in the slipstream.\66\ 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<INF>2</INF> emissions.\67\ 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<INF>2</INF> provided through the IRA.\68\
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\66\ U.S. Department of Energy (DOE). Carbon Capture
Opportunities for Natural Gas Fired Power Systems. <a href="https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems">https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems</a>.
\67\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power
plant with carbon capture in Scotland. Reuters. <a href="https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/">https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/</a>.
\68\ 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.
<a href="https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/">https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/</a>.
---------------------------------------------------------------------------

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

[[Page 33255]]

a fuel to generate electricity. Hydrogen contains no carbon, and when
combusted in a turbine, produces zero direct CO<INF>2</INF> 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.\69\ 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.\70\ 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.\71\ 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.'' \72\
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\69\ <a href="https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf">https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf</a>.
\70\ <a href="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.forbes.com/sites/mitsubishiheavyindustries/2021/07/30/eager-to-become-hydrogen-ready-power-plants-turn-to-dual-fuel-turbines/?sh=38ddea053476</a>.
\71\ <a href="https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf">https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf</a>.
\72\ <a href="https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf">https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf</a>.
---------------------------------------------------------------------------

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.\73\ 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.\74\ 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.\75\
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\73\ <a href="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/">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/</a>.
\74\ GE-powered gas-fired plant in Ohio now burning hydrogen
(<a href="http://power-eng.com">power-eng.com</a>).
\75\ 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.
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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

[[Page 33256]]

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.\76\ 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,\77\ 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.
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\76\ U.S. Energy Information Administration (EIA). Monthly
Energy Review and Short-Term Energy Outlook, March 2016. <a href="https://www.eia.gov/todayinenergy/detail.php?id=25392">https://www.eia.gov/todayinenergy/detail.php?id=25392</a>.
\77\ U.S. Department of Energy (DOE). August 2022. The Inflation
Reduction Act Drives Significant Emissions Reductions and Positions
America to Reach Our Climate Goals. <a href="https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf">https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf</a>.
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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.\78\
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\78\ U.S. Energy Information Administration (EIA). Annual Energy
Review, table 8.2b Electricity net generation: electric power
sector. <a href="https://www.eia.gov/totalenergy/data/annual/">https://www.eia.gov/totalenergy/data/annual/</a>.
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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.\79\
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.\80\ 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.\81\ 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.
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\79\ 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. <a href="https://www.eia.gov/todayinenergy/detail.php?id=25392">https://www.eia.gov/todayinenergy/detail.php?id=25392</a>.
\80\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, March 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
\81\ 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. <a href="https://www.eia.gov/todayinenergy/detail.php?id=44636">https://www.eia.gov/todayinenergy/detail.php?id=44636</a>.
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Since 2010, the power sector's total installed capacity \82\ has
increased by

[[Page 33257]]

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.
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\82\ 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).
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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.\83\
Moreover, average annual capacity factors for coal-fired steam
generating units have declined from 67 to 49 percent since 2010,\84\
indicating that a larger share of units are operating in non-base load
fashion.
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\83\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
\84\ U.S. Energy Information Administration (EIA). Electric
Power Annual 2021, table 1.2.
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Older power plants also tend to become uneconomic over time as they
become more costly to maintain and operate,\85\ 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.\86\ To
further illustrate this trend, the existing coal-fired steam generating
units older than 40 years represent 71 percent (154 GW) \87\ 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.\88\ As discussed further in this
section, projections anticipate that this trend will continue.
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\85\ U.S. Energy Information Administration (EIA). U.S. coal
plant retirements linked to plants with higher operating costs.
December 2019. <a href="https://www.eia.gov/todayinenergy/detail.php?id=42155">https://www.eia.gov/todayinenergy/detail.php?id=42155</a>.
\86\ 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.
\87\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
\88\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. <a href="https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs">https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs</a>.
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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.\89\ In 2015, less than 900 MMst were
produced, and in 2020, the total dropped to 535 MMst, the lowest output
since 1965.
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\89\ U.S. Energy Information Administration (EIA). Annual Coal
Report. Table ES-1. October 2022. <a href="https://eia.gov/coal/annual/pdf/tableES1.pdf">https://eia.gov/coal/annual/pdf/tableES1.pdf</a>.
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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.\90\ 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.
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\90\ U.S. Energy Information Administration (EIA). Natural Gas
Explained. December 2022. <a href="https://www.eia.gov/energyexplained/natural-gas/">https://www.eia.gov/energyexplained/natural-gas/</a>.
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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.\91\
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.
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\91\ U.S. Energy Information Administration (EIA). Natural gas
explained. Where our natural gas comes from. <a href="https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php">https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php</a>.
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As the production of natural gas has increased, the annual average
price has declined during the same period.\92\ 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

[[Page 33258]]

price in July 2022 was $59.18/MWh and the price for Central Appalachian
coal was $78.25/MWh for the same month.\93\
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\92\ U.S. Energy Information Administration (EIA). Natural Gas
Annual, September 2021. <a href="https://www.eia.gov/energyexplained/natural-gas/prices.php">https://www.eia.gov/energyexplained/natural-gas/prices.php</a>.
\93\ 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.
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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.\94\ 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.
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\94\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, July 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
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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.\95\
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\95\ National Electric Energy Data System (NEEDS) v.6.
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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.\96\ 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.
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\96\ 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. <a href="https://www.eia.gov/todayinenergy/detail.php?id=55419">https://www.eia.gov/todayinenergy/detail.php?id=55419</a>.
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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).\97\
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\97\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 7.2B Electricity Net Generation: Electric Power
Sector, May 2022. <a href="https://www.eia.gov/totalenergy/data/monthly/">https://www.eia.gov/totalenergy/data/monthly/</a>.
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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.\98\ The average levelized cost of
energy for utility-scale solar photovoltaics has fallen from $227/MWh
in 2010 to $33/MWh in 2021.\99\ 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.
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\98\ U.S. Department of Energy (DOE), Land-Based Wind Market
Report: 2022 Edition, 2022. <a href="https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition">https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition</a>.
\99\ Lawrence Berkeley National Laboratory (LBNL), Utility-Scale
Solar Technical Brief, 2022 Edition, September 2022. <a href="https://emp.lbl.gov/utility-scale-solar">https://emp.lbl.gov/utility-scale-solar</a>.
\100\ <a href="https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html">https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html</a>.
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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.
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\101\ U.S. Energy Information Administration (EIA), Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators, July 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
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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

[[Page 33259]]

(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\
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\102\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2021 Form EIA-860. <a href="https://www.eia.gov/electricity/data/eia860/">https://www.eia.gov/electricity/data/eia860/</a>.
\103\ U.S. Energy Information Administration (EIA). Annual
Electric Power Industry Report, 2021 Form EIA-861. <a href="https://www.eia.gov/electricity/data/eia861/">https://www.eia.gov/electricity/data/eia861/</a>.
\104\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2019 Form EIA-860. <a href="https://www.eia.gov/analysis/studies/electricity/batterystorage/">https://www.eia.gov/analysis/studies/electricity/batterystorage/</a>.
\105\ U.S. Energy Information Administration (EIA). Today in
Energy. U.S. battery storage capacity will increase significantly by
2025. December 2022. <a href="https://www.eia.gov/todayinenergy/detail.php?id=54939">https://www.eia.gov/todayinenergy/detail.php?id=54939</a>.
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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\
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\106\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. <a href="https://www.eia.gov/electricity/data/eia860m/">https://www.eia.gov/electricity/data/eia860m/</a>.
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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.
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\107\ U.S. Nuclear Regulatory Commission (NRC). Status of
Subsequent License Renewal Applications. April 2023. <a href="https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html">https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html</a>.
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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\
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\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. <a href="https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf">https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf</a>.
\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). <a href="https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear">https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear</a>.
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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<INF>2</INF>,
CH<INF>4</INF>, N<INF>2</INF>O, HFCs, PFCs, and SF<INF>6</INF>. Of
these, CO<INF>2</INF> is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO<INF>2</INF>
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\111\
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\111\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. <a href="https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide">https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide</a>.
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The amount of CO<INF>2</INF> 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<INF>2</INF> in
relation to the energy they produce when combusted. The amount of
CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF>/MMBtu.112 113 The
average for coal is 216 lb CO<INF>2</INF>/MMBtu, but varies between 206
to 229 lb CO<INF>2</INF>/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<INF>2</INF>/MMBtu.
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\112\ Natural gas is primarily CH<INF>4</INF>, which has a
higher hydrogen to carbon atomic ratio, relative to other fuels, and
thus, produces the least CO<INF>2</INF> per unit of heat released.
In addition to a lower CO<INF>2</INF> 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<INF>2</INF>/kWh and 0.91 lb
CO<INF>2</INF>/kWh, respectively. <a href="http://www.eia.gov/tools/faqs/faq.php?id=74&t=11">www.eia.gov/tools/faqs/faq.php?id=74&t=11</a>.
\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. <a href="https://www.eia.gov/environment/emissions/co2_vol_mass.php">https://www.eia.gov/environment/emissions/co2_vol_mass.php</a>.
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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<INF>2</INF> emissions,
for the years 1990-2020.
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\115\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. <a href="https://cfpub.epa.gov/ghgdata">https://cfpub.epa.gov/ghgdata</a>.
\116\ Sinks are a physical unit or process that stores GHGs,
such as forests or underground or deep-sea reservoirs of carbon
dioxide.
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According to the latest inventory, in 2021, total U.S. GHG
emissions were 6,340 million metric tons of carbon dioxide equivalent
(MMT CO<INF>2</INF>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

[[Page 33260]]

(23.5 percent). In terms of annual CO<INF>2</INF> emissions, the power
sector was responsible for 30.6 percent (1,541 MMT CO<INF>2</INF>e) of
the nation's 2021 total.
CO<INF>2</INF> emissions from the power sector have declined by 36
percent since 2005 (when the power sector reached annual emissions of
2,400 MMT CO<INF>2</INF>, its historical peak to date).\117\ The
reduction in CO<INF>2</INF> 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<INF>2</INF> 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<INF>2</INF>
emissions were below 1,000 MMT. In 2020, emissions of CO<INF>2</INF>
from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909
MMT due to increased demand. By contrast, CO<INF>2</INF> emissions from
natural gas-fired generation have almost doubled since 2005, increasing
from 319 MMT to 613 MMT in 2021, and CO<INF>2</INF> 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.
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\117\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. <a href="https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all">https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all</a>.
\118\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 11.6. September 2022. <a href="https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf">https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf</a>.
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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<INF>2</INF> 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<INF>2</INF>
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<INF>2</INF> 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<INF>2</INF> in the U.S., and, despite
the emission reductions since 2005, current CO<INF>2</INF> levels
continue to endanger human health and welfare. Further, as sources in
other sectors of the economy turn to electrification to decarbonize,
future CO<INF>2</INF> reductions from fossil fuel-fired EGUs have the
potential to take on added significance and increased benefits.
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\119\ 80 FR 63662 (October 23, 2015).
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The Legislative, Market, and State Law Context

Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the IIJA \120\ (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 electric grid; $6 billion in
financial support for existing nuclear reactors that are at risk of
closing and being replaced by high-emitting resources; and more than
$700 million for upgrades to the existing hydroelectric fleet. The IIJA
established the Carbon Dioxide Transportation Infrastructure Finance
and Innovation Program to provide flexible Federal loans and grants for
building CO<INF>2</INF> pipelines designed with excess capacity,
enabling integrated carbon capture and geologic storage. The IIJA also
allocated $21.5 billion to fund new programs to support the
development, demonstration, and deployment of clean energy
technologies, such as $8 billion for the development of regional clean
hydrogen hubs. Other clean energy technologies with IIJA funding
include carbon capture, geologic sequestration, direct air capture,
grid-scale energy storage, and advanced nuclear reactors. States,
Tribes, local communities, utilities, and others are eligible to
receive funding.
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\120\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/3684/text">https://www.congress.gov/bill/117th-congress/house-bill/3684/text</a>.
\121\ <a href="https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDING-A-BETTER-AMERICA-V2.pdf">https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDING-A-BETTER-AMERICA-V2.pdf</a>.
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The IRA, which President Biden signed on August 16, 2022,\122\ has
the potential for even greater impacts on the electric power sector.
With an estimated $369 billion in Energy Security and Climate Change
programs over the next 10 years, covering grant funding and tax
incentives, the IRA provides significant investments in non GHG-
emitting generation. For example, one of the conditions set by Congress
for the expiration of the Clean Electricity Production Tax Credits of
the IRA, found in section 13701, is a 75 percent reduction in GHG
emissions from the power sector below 2022 levels. The IRA also
contains the Low Emission Electricity Program (LEEP) with funding
provided to the EPA with the objective to reduce GHG emissions from
domestic electricity generation and use through promotion of
incentives, tools to facilitate action, and use of CAA regulatory
authority. In particular, CAA section 135, added by IRA section 60107,
requires the EPA to conduct an assessment of the GHG emission
reductions expected to occur from changes in domestic electricity
generation and use through fiscal year 2031 and, further, provides the
EPA $18 million ``to ensure that reductions in [GHG] emissions are
achieved through use of the existing authorities of [the Clean Air
Act], incorporating the assessment. . ..'' CAA section 135(a)(6).
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\122\ <a href="https://www.congress.gov/bill/117th-congress/house-bill/5376/text">https://www.congress.gov/bill/117th-congress/house-bill/5376/text</a>..
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The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. These provisions are aimed
at reducing emissions of GHGs from new and existing generating assets,
with tax credits for carbon capture, utilization, and storage (CCUS)
and clean hydrogen production providing a pathway for the use of coal
and natural gas as part of a low-GHG electricity grid. Finally, with
provisions such as the Methane Emissions Reduction Program, Congress
demonstrated a focus on the importance of actions to address methane
emissions from petroleum and natural gas systems.
To assist states and utilities in their decarbonizing efforts, and
most germane to these proposed rulemakings, the IRA increased the tax
credit incentives for capturing and storing CO<INF>2</INF>, including
from industrial sources, coal-fired steam generating units, and natural
gas-fired stationary combustion turbines. The increase in credit
values, found in section 13104 (which revises IRC section 45Q), is 70
percent, equaling $85/metric ton for CO<INF>2</INF> captured and
securely stored in geologic formations and $60/metric ton for
CO<INF>2</INF> captured and utilized or securely stored incidentally in
conjunction with

[[Page 33261]]

enhanced oil recovery (EOR).\123\ The CCUS incentives include 12 years
of credits that can be claimed at the higher credit value beginning in
2023 for qualifying projects. These incentives will significantly cut
costs and are expected to accelerate the adoption of CCS in the utility
power and other industrial sectors. Specifically for the power sector,
the IRA requires that a qualifying carbon capture facility have a
CO<INF>2</INF> capture design capacity of not less than 75 percent of
the baseline CO<INF>2</INF> production of the unit and that
construction must begin before January 1, 2033. Tax credits under 45Q
can be combined with other tax credits, in some circumstances, and with
State-level incentives, including California's low carbon fuel standard
which is a market-based program with fuel-specific carbon intensity
benchmarks.\124\ The magnitude of this incentive is driving investment
and announcements, evidenced by the increased number of permit
applications for geologic sequestration.
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\123\ 26 U.S.C. 45Q.
\124\ Global CCS Institute. (2019). The LCFS and CCS Protocol:
An Overview for Policymakers and Project Developers. Policy report.
<a href="https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf">https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf</a>.
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The new provisions in section 13204 (IRC section 45V) codify
production tax credits for `clean hydrogen' as defined in the
provision. The value of the credits earned by a project is tiered (four
different tiers) and depends on the estimated GHG emissions of the
hydrogen production process from well-to-gate. The credits range from
$3/kg H<INF>2</INF> for 0.0 to 0.45 kilograms of CO<INF>2</INF>-
equivalent emitted per kilogram of low-GHG hydrogen produced (kg
CO<INF>2</INF>e/kg H<INF>2</INF>) down to $0.6/kg H<INF>2</INF> for 2.5
to 4.0 kg CO<INF>2</INF>e/kg H<INF>2</INF> (assuming wage and
apprenticeship requirements are met). Projects with GHG emissions
greater than 4.0 kg CO<INF>2</INF>e/kg H<INF>2</INF> are not eligible.
According to the DOE, current costs for hydrogen produced from
renewable energy are approximately $5/kg H<INF>2</INF>.\125\ These
production costs could decline by 2025 to between $2.5 and $2.7/kg
H<INF>2</INF> (not including the production tax credits).\126\
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\125\ U.S. Department of Energy (DOE). Hydrogen and Fuel Cell
Technologies Office. Hydrogen Shot. <a href="https://www.energy.gov/eere/fuelcells/hydrogen-shot">https://www.energy.gov/eere/fuelcells/hydrogen-shot</a>.
\126\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. <a href="https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies">https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies</a>.
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The clean hydrogen production tax credit is expected to incentivize
the production of low-GHG hydrogen and ultimately exert downward
pressure on costs.\127\ Low-cost and widely available low-GHG hydrogen
has the potential to become a material decarbonization lever in the
power sector as the use of low-GHG hydrogen in stationary combustion
turbines reduces direct GHG emissions as hydrogen releases no
CO<INF>2</INF> when combusted. The tiered eligibility requirements for
the clean hydrogen production tax credit also incentivize the lowest-
GHG emissions production processes.
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\127\ Larsen, J., King, B., Kolus, H., Dasari, N., Hiltbrand,
G., Herndon, W. (August 12, 2022). A Turning Point for US Climate
Progress: Assessing the Climate and Clean Energy Provisions in the
Inflation Reduction Act. Rhodium Group. <a href="https://rhg.com/research/climate-clean-energy-inflation-reduction-act/">https://rhg.com/research/climate-clean-energy-inflation-reduction-act/</a>.
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Both IRC 45Q and 45V are eligible for additional provisions that
increase the value and usability of the credits. Certain tax-exempt
entities, such as electric co-ops, may use direct pay for the full 12-
or 10-year lifetime of the credits to monetize the credits directly as
cash refunds rather than through tax equity transactions. Tax-paying
entities may elect to have direct payment of 45Q or 45V credits for
five consecutive years. Tax-paying entities may also elect to transfer
credits to unrelated taxpayers, enabling direct monetization of the
credits again without relying on tax equity transactions.
The production tax credit is not the only provision in the IRA
designed to incentivize low-GHG hydrogen. Projects may also access an
investment tax credit (ITC) under IRC section 48. For example,
manufacturers of clean hydrogen production equipment, like
electrolyzers, may apply under IRC section 48C (the Advanced
Manufacturing Tax Credit). And the manufacturing facility for
electrolyzers could receive credits under section 48C while the
resulting hydrogen production facility could then earn credits under
section 45V (this form of stacking is allowed by statute). However, the
same project may not claim ITC credits under section 48C while claiming
PTC credits under section 45V. Projects may not generally combine
credits from IRC section 45V with credits in IRC section 45Q. Hydrogen
production tax credits became available in January 2023 for eligible
new projects. Entities that commence construction between 2023 and 2032
can claim credits for the first 10 years of production.
The magnitude of this incentive--combined with those in the IIJA
such as the $8 billion for regional hydrogen hubs and $1.5 billion for
electrolyzer advancement--should accelerate the production of low-GHG
hydrogen for use in a broad range of applications across many sectors,
including the utility power sector.\128\
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\128\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. <a href="https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies">https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies</a>.
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Many of the IRA tax credit incentives are directed toward low- and
zero-emission electric generation. They are designed to lower costs and
market barriers to bring new zero-emitting generation and energy
storage capacity online, to retain existing zero-emitting generators,
and the energy efficiency tax credits are designed to reduce
electricity demand. These financial tools have been used historically
and shown to be a principal policy driver, buttressed by State
renewable and clean energy standards, for incentivizing deployment of
low- and zero-emitting generation.129 130
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\129\ Impacts of Federal Tax Credit Extensions on Renewable
Deployment and Power Sector Emissions, National Renewable Energy
Laboratory (NREL), February 2016.
\130\ A Retrospective Assessment of Clean Energy Investments in
the Recovery Act, February 2016, U.S. Executive Office of the
President, Memorandum.
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For example, the IRA expanded and extended the existing section
13101 (IRC section 45) production tax credits for new solar, wind,
geothermal, and other eligible zero- or low-GHG emissions energy
sources. The production tax credit (PTC) provides credits in a 10-year
stream for each MWh of clean energy produced. The IRA indexed the PTC
on inflation, increasing the credit amount to $27.50/MWh for facilities
meeting certain wage and apprenticeship requirements. For context, the
energy price in the nation's largest wholesale energy market, PJM,\131\
is typically between $20/MWh and $90/MWh depending on timing, load, and
transmission congestion.
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\131\ PJM Interconnection LLC (PJM) is a regional transmission
organization (RTO) serving all or parts of Delaware, Illinois,
Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the
District of Columbia.
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In parallel, the existing investment tax credits in section 13101
(IRC section 48) were also expanded and extended in the IRA. Taxpayers
must elect between the ITC and the PTC for each applicable project. The
ITC enables taxpayers to recoup up to 30 percent of project costs for
technologies such as solar, geothermal, fiberoptic solar, fuel cells,
microturbines, small wind, offshore wind, combined heat and power
(CHP), and waste energy recovery for investments meeting certain wage
and apprenticeship requirements. There are also a range of bonus
credits available

[[Page 33262]]

if certain criteria are met, for example for meeting domestic content
and energy communities' requirements with each earning an additional 10
percent credit. The IRA expanded eligibility to include storage
technologies as well as some non-storage technologies.
The IRA also tied the availability of tax credits explicitly to
reductions of GHG emissions from the power sector. Sections 13701 and
13702 enacted technology-neutral production and investment tax credits
for projects placed in service after 2025 that have GHG emissions rates
of zero or less. These credits are available until the phaseout is
triggered when the power sector's GHG emissions fall below 25 percent
of 2022 levels.
Following State practices, Congress also included a zero-emission
nuclear power production credit in the IRA to ensure existing in-
service nuclear generators are retained for their contribution to base
load zero-carbon emitting electricity. When labor and apprenticeship
requirements are met, the credit price is $15/MWh. The credit amount
declines when gross receipts of services provided with electricity rise
above a specified level. The program begins in 2024 with credit streams
available for nine years. This PTC is complementary to the $6 billion
for nuclear advancements the IIJA authorized and appropriated to the
DOE. New nuclear plants, including small modular reactors, would be
eligible for either the technology-neutral Clean Electricity Production
or Investment Credit (IRC section 45Y and 48E).
In the evaluation of these proposed actions, many of the
technologies that receive investment under recent Federal legislation
are not directly considered, as the EPA has not evaluated the new
generation technologies that entities could employ as alternatives to
fossil fuel-fired EGUs in its assessment of the BSER. As the discussion
of that assessment will make clear later in this preamble, the EPA's
inquiry has focused on ``measures that improve the pollution
performance of individual sources.'' \132\ However, these overarching
incentives and policies are important context for this rulemaking.
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\132\ West Virginia v. EPA, 142 S. Ct. 2587, 2615 (2022).
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The following section (section IV.E.2) includes a review of
integrated resource plans (IRPs) filed by public utilities that
prioritize GHG reductions. IRPs demonstrate how utilities plan to meet
future forecasted energy demand while ensuring reliable and cost-
effective service. These IRPs demonstrate that most power companies
intend to meet their GHG reduction targets by retiring aging coal-fired
steam generating EGUs and replacing them with a combination of
renewable resources, energy storage, other non-emitting technologies,
and natural gas-fired combustion turbines. Many IRPs further
demonstrate the realization of power companies that to meet their GHG
reduction targets, their natural gas-fired assets will need to occupy a
much smaller GHG footprint through a combination of hydrogen, CCS, and
reduced utilization. The IRA is designed to encourage this trend. For
example, in addition to the provisions outlined above, including the 10
percent bonus value applied in `energy communities' that include
fossil-related properties, the IRA created grant and loan funding
sources for hard-to-abate energy assets. Section 22004 of the IRA
authorizes $9.7 billion in financing for rural electric co-operatives
and providers to invest in cleaner technologies to achieve GHG
reductions across rural electric systems while buttressing resilience
and reliability. Additionally, section 50144 of the IRA, known as the
Energy Infrastructure Reinvestment Financing provision, provides $5
billion for backing $250 billion in low-cost loans for utilities to
repower, repurpose, or replace existing infrastructure that has ceased
operations, or to enable operating energy infrastructure to reduce air
pollution or GHG emissions. The financing in this provision enables a
utility to repurpose an existing fossil site, such as a retired coal-
fired power plant, or add CCS, renewable generation, or hydrogen
capability to an operating coal- or natural gas-fired power plant and
retain community jobs while reducing GHG emissions.
2. Commitments by Utilities To Reduce GHG Emissions
The broad trends away from coal-fired generation and toward lower-
emitting generation are reflected in the recent actions and announced
plans of many utilities across the industry. As highlighted later in
this section, through planning documents, IRPs, filings with State and
local public utility commissions, and news releases, many utilities
have made public commitments to voluntarily cease operating coal-fired
generation and move toward zero- and low-GHG energy generation. Many
utilities and other power generators have announced plans to increase
their renewable energy holdings and continue reducing GHG emissions,
regardless of any potential Federal regulatory requirements. For
example, 50 power producers that are members of the Edison Electric
Institute have announced CO<INF>2</INF> reduction goals, two-thirds of
which include net-zero carbon emissions by 2050.\133\ This trend is not
unique to the largest owner-operators of coal-fired EGUs; smaller
utilities, public power cooperatives, and municipal entities are also
contributing to these changes.
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\133\ See Comments of Edison Electric Institute to EPA's Pre-
Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired
Power Plants, Docket ID No. EPA-HQ-OAR-2022-0723, November 18, 2022
(``Fifty EEI members have announced forward-looking carbon reduction
goals, two-third 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.'').
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Some of the largest electric utilities that have publicly announced
near- and long-term GHG reduction commitments, many with emission
reduction targets of at least 80 percent (relative to 2005 levels
unless otherwise noted), include:

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This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.